Mid-Con Energy Partners LP
Annual Report 2017

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 Form 10–K ☒☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2017OR ☐☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Commission File No.: 1-35374 Mid-Con Energy Partners, LP(Exact name of registrant as specified in its charter) Delaware45–2842469(State or other jurisdiction ofincorporation or organization)(I.R.S. EmployerIdentification No.)2431 East 61st Street, Suite 850Tulsa, 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 InterestsNASDAQ 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 preceding12 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 past90 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 andposted 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 andpost 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’sknowledge, 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 “largeaccelerated 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 financialaccounting 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 ofthe 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.Business6Item 1A.Risk Factors16Item 1B.Unresolved Staff Comments32Item 2.Properties32Item 3.Legal Proceedings35Item 4.Mine Safety Disclosures35 PART II Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities36Item 6.Selected Financial Data37Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations37Item 7A.Quantitative and Qualitative Disclosures About Market Risk47Item 8.Financial Statements and Supplementary Data48Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure72Item 9A.Controls and Procedures72Item 9B.Other Information72 PART III Item 10.Directors, Executive Officers and Corporate Governance73Item 11.Executive Compensation77Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters83Item 13.Certain Relationships and Related Transactions, and Director Independence84Item 14.Principal Accounting Fees and Services86 PART IV Item 15.Exhibits87 Signatures 90 iGLOSSARYThe following is a list of certain acronyms and terms generally used in the industry and throughout this document. The definitions of proveddeveloped reserves, proved reserves and proved undeveloped reserves have been excerpted from the applicable definitions contained in Rule 4-10(a) ofRegulation S-X. AROAsset retirement obligations.BasinA large depression on the earth's surface in which sediments accumulate.BblOne stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.Bbl/dOne Bbl per dayBehind pipeReserves associated with recompletion projects which have not been previously produced.BoeBarrel 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 thecommodities.Boe/dOne Boe per day.BtuOne British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of waterby one degree Fahrenheit.Class A Preferred UnitsClass A Convertible Preferred Units issued on August 11, 2016.Class B Preferred UnitsClass B Convertible Preferred Units issued on January 31, 2018.Conventional hydraulic fracturingHydraulic fracturing is used to stimulate production from new and existing oil and natural gas wells. Largevolumes of fracturing fluids, or “fracing fluids,” are pumped deep into the well at high pressures sufficient tocause the reservoir rock to break or fracture. Almost all frac fluid mixtures are comprised of more than95 percent water. As the pressure builds within the well, rock beds begin to crack. More fluid is added whilethe pressure is increased until the rock beds finally fracture, creating channels for trapped oil and natural gasto flow into the well bore and up to the surface. The fractures are kept open with proppants made of smallgranular 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 paththat connects the reservoir to the well. These new paths increase the rate that fluids can be produced from thereservoir formations, in some cases by many hundreds of percent.Developed acreageAcres spaced or assigned to productive wells or wells capable of production.Development wellA well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizonknown to be productive.Dry holeA well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from thesale of such production would exceed production expense and taxes.EOREnhanced oil recovery.EPAU.S. Environmental Protection Agency.Exploratory wellA well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oilor 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 wellA well drilled to extend the limits of a known reservoir.FieldAn area comprised of multiple leases in close proximity to one another that typically produce from the samereservoirs and may or may not be produced under waterflood.GAAPGenerally Accepted Accounting Principles in the United States of America.GHGGreenhouse gas.Gross wellsThe number of wells in which a working interest is owned.Injection wellA well employed for the introduction of water, gas or other fluid under pressure into an underground stratum.LIBORLondon Interbank Offered Rate.MBblsOne thousand Bbls.MBoeOne thousand Boe.MBtuOne thousand Btu.Mboe/dOne thousand Boe per day.McfOne thousand cubic feet.Mcf/dOne thousand cubic feet per day.MMBoeOne million Boe.MMBtuOne million Btu.1MMcfOne million cubic feet of natural gas.NASDAQNational Association of Securities Dealers Automated Quotation System Global Select Market.NGLsNatural gas liquids.Net productionProduction that is owned by us, less royalties and production due others.Net revenue interestA working interest owner’s gross working interest in production, less any royalty, overriding royalty,production payment and net profits interests.Net wellThe total of fractional working interests owned in a gross well.NYMEXNew York Mercantile Exchange.OilOil and condensate.Partnership AgreementSecond Amendment to First Amended and Restated Agreement of Limited Partnership of Mid-Con EnergyPartners, LP, dated as of January 31, 2018.Preferred UnitsClass A Preferred Units and Class B Preferred Units.Preferred UnitholdersThe holders of Preferred Units.Productive wellA well that is producing or that is mechanically capable of production.Proved developed reservesProved reserves that can be expected to be recovered from existing wells with existing equipment andoperating methods.Proved reservesThose quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can beestimated with reasonable certainty to be economically producible, from a given date forward, from knownreservoirs, and under existing economic conditions, operating methods, and government regulations, prior tothe time at which contracts providing the right to operate expire, unless evidence indicates that renewal isreasonably 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 certainthat it will commence the project, within a reasonable time. The area of the reservoir considered as provedincludes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilledportions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to containeconomically producible oil or natural gas on the basis of available geoscience and engineering data. In theabsence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest knownhydrocarbons, as seen in a well penetration unless geoscience, engineering or performance data and reliabletechnology establishes a lower contact with reasonable certainty. Where direct observation from wellpenetrations 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 reasonablecertainty. Reserves which can be produced economically through application of improved recoverytechniques (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 thereservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or otherevidence using reliable technology establishes the reasonable certainty of the engineering analysis on whichthe project or program was based; and (ii) the project has been approved for development by all necessaryparties and entities, including governmental entities. Existing economic conditions include prices and costsat which economic producibility from a reservoir is to be determined. The price shall be the average priceduring the twelve-month period prior to the ending date of the period covered by the report, determined as anunweighted arithmetic average of the first-day-of-the-month price for each month within such period, unlessprices 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, orfrom existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilledacreage shall be limited to those directly offsetting development spacing areas that are reasonably certain ofproduction when drilled, unless evidence using reliable technology exists that establishes reasonablecertainty of economic producibility at greater distances. Undrilled locations can be classified as havingundeveloped reserves only if a development plan has been adopted indicating that they are scheduled to bedrilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shallestimates for proved undeveloped reserves be attributable to any acreage for which an application of fluidinjection or other improved recovery technique is contemplated, unless such techniques have been provedeffective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliabletechnology establishing reasonable certainty.Realized priceThe cash market price, less all expected quality, transportation and demand adjustments.RecompletionThe completion for production of an existing wellbore in another formation from that which the well has beenpreviously completed. Reserves associated with recompletion are also referred to as “behind pipe.”ReservesParts of mineral deposits which could be economically and legally extracted or produced at the time of thereserve determination.ReservoirA porous and permeable underground formation containing a natural accumulation of producible oil and/ornatural gas that is confined by impermeable rock or water barriers and is individual and separate from otherreserves.SECSecurities and Exchange Commission.SpacingThe 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 priceThe cash market price without reduction for expected quality, transportation and demand adjustments.Standardized measureThe 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 andincome tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Becausewe are a limited partnership, we are generally not subject to federal or state income taxes and thus make noprovision for federal or state income taxes in the calculation of our standardized measure. Standardizedmeasure does not give effect to derivative transactions.Undeveloped acreageAcreage owned or leased on which wells can be drilled or completed to a point that would permit theproduction of commercial quantities of oil and natural gas regardless of whether such acreage contains provedreserves.UnitA contiguous geographic area that was established and approved by state oil and natural gas commissions forsecondary recovery.UnitizationThe process of obtaining approval from working interest owners, mineral owners and regulatory agencies toconduct secondary (e.g., waterflooding) or tertiary operations.WellboreThe hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also calledwell or borehole.Working interestThe operating interest that gives the owner the right to drill, produce and conduct operating activities on theproperty and a share of production.WorkoverOperations on a producing well to restore or increase production.WTIWest Texas Intermediate, also called Texas light sweet, is a type of crude oil used as a benchmark in oilpricing. It is the underlying commodity of NYMEX’s oil future contracts.3NAMES OF ENTITIESAs used in this Form 10-K, unless we indicate otherwise: Founderscollectively refers to Charles R. Olmstead, S. Craig George and Jeffrey R. Olmstead.Our general partnerrefers to Mid-Con Energy GP, LLC.Mid-Con Affiliaterefers to Mid-Con Energy III, LLC, and its subsidiaries, which is an affiliate of our general partner.ME3 Oilfield Servicerefers to ME3 Oilfield Service, LLC, which is a wholly owned subsidiary of our Mid-Con Affiliate.ME2 Well Servicesrefers to ME2 Well Services, LLC, which is an affiliate of our Mid-Con Affiliate and Mid-Con Energy Operating.Mid-Con Energy Partnersthe “partnership,” “we,” “our,” “us,” “company” or like terms when used refer to Mid-Con Energy Partners, LP, a Delaware limitedpartnership, and its subsidiaries.Mid-Con EnergyOperatingrefers to Mid-Con Energy Operating, LLC, an affiliate of our general partner.Mid-Con EnergyPropertiesrefers to Mid-Con Energy Properties, LLC, our wholly owned subsidiary.Our predecessorcollectively refers to Mid-Con Energy Corporation, prior to June 30, 2009, and to Mid-Con Energy I, LLC, and Mid-Con EnergyII, LLC, on a combined basis, thereafter, our respective predecessors for accounting purposes.Yorktowncollectively refers to Yorktown Partners, LLC, Yorktown Energy Partners VI, LP, Yorktown Energy Partners VII, LP, YorktownEnergy Partners VIII, LP, Yorktown Energy Partners IX, LP, and/or Yorktown Energy Partners X, LP.4FORWARD-LOOKING STATEMENTSThis Annual Report on Form 10-K (“Form 10-K”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (each a “forward–looking statement”). These forward–lookingstatements 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 FinancialCondition and Results of Operations” and other items within this Annual Report on Form 10-K. In some cases, forward-looking statements can be identifiedby 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 andassumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and otherfactors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertaintiesthat are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that theforward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader thatsuch statements will be realized or that the forward-looking events will occur. Actual results may differ materially from those anticipated or implied in theforward-looking statements due to factors described in the “Risk Factors” section and elsewhere in this Annual Report on Form 10-K. All forward-lookingstatements 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 resultof new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on ourbehalf.5PART IITEM 1.BUSINESSMid-Con Energy Partners, LP, is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition anddevelopment 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 Delawarelimited liability company. Our limited partner units (“common units”) are listed under the symbol “MCEP” on the NASDAQ.OverviewWe operate as one business segment engaged in the ownership, acquisition and development of producing oil and natural gas properties. As ofDecember 31, 2017, our properties were located primarily in the Mid-Continent and Permian Basin regions of the United States in Oklahoma and Texas coreareas. Our properties primarily consist of mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low productiondecline rates.Our management team has significant industry experience, especially with waterflood projects and, as a result, our operations focus primarily onenhancing 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 tomake and, over time, increase distributions to our unitholders. In order to enhance the stability of our cash flow for the benefit of our unitholders, wegenerally 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 StrategiesThe 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 StrengthsWe believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective ofgenerating 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 relativelypredictable production profiles that provide growth potential through ongoing response to waterflooding and that have modest capitalrequirements; •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 resultof 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 withYorktown; •maintaining a high degree of operational control by operating a high percentage of our properties through our affiliate, Mid-Con EnergyOperating, 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 OperationsAs of December 31, 2017, our properties were primarily located in the Mid-Continent and Permian regions of the United States in Oklahoma andTexas core areas. These core areas are generally composed of multiple fields and waterflood units that are in close proximity to one another, produce fromgeologically similar reservoirs and utilize similar recovery methods. Focusing on these core areas allows us to apply our cumulative technical andoperational knowledge to ongoing property development and to better predict future rates of recovery.OklahomaOur Oklahoma properties are located in six counties in Oklahoma: Cleveland, Creek, Oklahoma, Osage, Pawnee and Seminole Counties. The majorityof our Oklahoma properties are being produced under waterflood and are operated by Mid-Con Energy Operating. At December 31, 2017, our averageworking 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.TexasOur Texas properties are located in eleven counties in Texas: Coke, Coleman, Fisher, Haskell, Jones, Kent, Liberty, Nolan, Runnels, Stonewall, andTaylor Counties. At December 31, 2017, we had an average working interest of approximately 95% in these properties. During 2017 we drilled 12 grossproducing 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 andaudited 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 % ofTotal % Proved Standardized Measure Core Area MBoe ProvedReserves % Oil DevelopedReserves Amount (1)($ in millions) % ofTotal 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 thefirst-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 forquality, transportation fees, location differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The average 12-month index priceswere $51.34 per Bbl for oil and $2.98 per MMBtu for natural gas for the 12 months ended December 31, 2017.Drilling ActivitiesThe following table sets forth information with respect to drilling activities during the periods indicated. The information should not be consideredindicative of future performance nor should a correlation be assumed between the numbers of productive wells drilled, quantities of reserves found oreconomic 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 HistoryThe 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 ordivestitures, the historical information presented below should not be interpreted as being indicative of future results.Production and Unit Costs per BOEThe 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 endedDecember 31, 2016, effect of net settlements on matured derivative instruments does not include the $5.8 million received and the $1.5 million of deferredpremiums paid upon early termination of previous oil derivative contracts in July 2016 or the related $2.8 million premiums paid at inception of the oilderivative contracts in January 2015.ProductionThe 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 atDecember 31, 2017, and 2016.(2) Hugoton properties were divested on July 28, 2016 and included properties in Colorado, Oklahoma and Texas.8Productive WellsThe following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2017. Productivewells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oilwells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own a working interest, and net wells arethe 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 withPUDs 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 asawaiting pipeline or facilities connections.OperationsGeneralWe operate 100% of our properties, as calculated on a Boe basis as of December 31, 2017, through our affiliate, Mid-Con Energy Operating. Wedesign 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). Theseservices 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 theparties’ 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 hoursutilizing lower pressures and volumes of fluid than are typically employed in multi-stage hydraulic fracturing jobs performed in connection withunconventional oil and natural gas shale plays. These services are not normally governed by long-term services contracts, but instead are generally performedunder 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 ServicesMid-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 technicalexpertise. 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 RelatedTransactions, and Director Independence - Agreements and Transactions with Affiliates” for more information.Administrative ServicesMid-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 discretionto 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 servicesprovided by Mid-Con Energy Operating pursuant to the services agreement, please see Item 13. “Certain Relationships and Related Transactions, andDirector Independence - Agreements and Transactions with Affiliates.”9Oil and Natural Gas LeasesThe typical oil lease agreement covering our properties provides for the payment of royalties to the mineral owner for all hydrocarbons produced fromany well drilled on the lease premises. As of December 31, 2017, the lessor royalties and other leasehold burdens on our properties ranged from less than12.5% 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 revenueinterest is 76.3%. Generally, most of our leases are held by production and do not require lease rental payments.Principal CustomersFor 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 customerscould 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 identifysubstitute 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 CommitmentsWe have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production in the near future under our existingcontracts.Hedging ActivitiesWe continue to enter into commodity derivative contracts with unaffiliated third parties that are also members of our banking group to achieve morepredictable cash flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. At December 31, 2017, our commodity derivativecontracts had maturities through 2019 and were comprised of price swaps, puts and collars. For a more detailed discussion of our hedging activities, see Note5 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data.”CompetitionWe operate in a highly competitive environment for acquiring properties and securing trained personnel. Many of our competitors possess and employfinancial resources substantially greater than ours, which can be particularly important in the areas in which we operate. These companies may have a greaterability to continue acquisition, and or exploration and production activities during periods of low commodity prices. Some of our competitors may alsopossess 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 andpurchase a greater number of properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reservesin the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Inaddition, 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 delayeddevelopment drilling and caused significant increases in the price for this equipment and personnel. We are unable to predict when, or if, such shortages mayoccur or how they would affect our development program.InsuranceIn accordance with industry practice, we maintain insurance against many potential operating risks to which our business could be exposed. Ourcoverage includes general liability, commercial umbrella liability, control of well, auto liability, property and equipment, worker’s compensation andemployer’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 legaland contractual liabilities arising out of property damage and bodily injury, among other things. The insurance policies contain maximum policy limits andin most cases, deductibles that must be met prior to recovery and are subject to certain customary exclusions and limitations. This insurance coverage is inaddition to the general and automobile liability policies and may be triggered if the general or automobile liability insurance policy limits are exceeded andexhausted. The control of well policy insures us for blowout risks associated with drilling, completing and operating our wells, including above groundpollution.These policies do not provide coverage for all liabilities, and no assurance can be given that the insurance coverage will be adequate to cover claimsthat 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 amaterial adverse effect on our financial position, results of operations and cash flows.10Environmental Matters and RegulationGeneralOur operations are subject to stringent and complex federal, tribal, state and local laws and regulations governing environmental protection as well asthe discharge of materials into the environment. These laws and regulations may, among other things (i) require the acquisition of permits to conductexploration, drilling and production operations; (ii) govern the types, quantities and concentration of various substances that can be released into theenvironment 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 remedialmeasures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and (vi) impose obligationsto reclaim and abandon wellsites. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminalpenalties, 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 oiland natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the U.S. Congress andfederal 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 anychanges 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 beunable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and wecannot provide assurances that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims fordamage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulationsand that continued compliance with existing requirements will not materially affect us, we can provide no assurance that we will not incur substantial costs inthe future related to revised or additional environmental regulations that could have a material adverse effect on our business, financial condition and resultsof operations.The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operationsare subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.Hazardous Substances and WasteThe federal Resource Conservation and Recovery Act, as amended, (“RCRA”), and comparable state statutes and their respective implementingregulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices ofthe EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal andstate regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous staterequirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil, if properlyhandled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’s less stringent solidwaste provisions, state laws or other federal laws. However, it is possible that certain oil exploration, development and production wastes now classified asnon-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 ofwastes, 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, andcomparable 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 anyonewho 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 thecosts 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 theenvironment and to seek to recover from responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other thirdparties 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.11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-sitelocations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous ownersor operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substancesdisposed 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 removeor 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 DischargesThe federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws, impose restrictions and strictcontrols regarding the discharge of pollutants, including oil and hazardous substances, into state waters and federal navigable U.S. waters The discharge ofpollutants 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 agencythat has been delegated authority for the program by the EPA. Federal, state and tribal regulatory agencies can impose administrative, civil and criminalpenalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Planrequirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination ofnavigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws required individualpermits 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 facilitiesthat 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 tothe prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certainonshore 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 andreporting of injection well activities, as well as prohibitions against the migration of injected fluids into underground sources of drinking water. We currentlyown a number of injection wells, used primarily for reinjection of produced waters that are subject to SDWA requirements.Hydraulic FracturingHydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rockformations. We employ conventional hydraulic fracturing techniques to increase the productivity of certain of our properties. The hydraulic fracturingprocess 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 authorityover certain hydraulic fracturing activities involving diesel under the SDWA and has published guidance documents related to this regulatory authority. Inaddition, from time to time, Congress has considered federal regulation of hydraulic fracturing including disclosure of the chemicals used in the hydraulicfracturing process. Several states in which we operate, including Texas and Oklahoma, have adopted rules requiring the disclosure of certain informationrelated to hydraulic fluids associated with wells that are hydraulically fractured. Additionally, some states and local governments have adopted, and otherstates are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, the State of Oklahoma has issueddirectives to shut-in or reduce the volume sent to disposal wells in the areas that have experienced recent earthquake activity. Other authorities areconsidering restrictions on the disposal of hydraulic fluids by deep well injection. We follow applicable industry standard practices and legal requirementsfor groundwater protection in our hydraulic fracturing activities. In the event that new or more stringent federal, state or local legal restrictions are adopted inareas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuitof 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 hydraulicfracturing. The EPA has completed a study of the potential environmental effects of hydraulic fracturing on drinking water resources and issued its finalreport in December 2016. The report concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances andidentified conditions under which such impacts can be more frequent or severe. In June 2016, the EPA published final pretreatment standards for oil andnatural gas extraction to ensure that wastewater from hydraulic fracturing activities is not sent to publicly owned treatment works. Subsequent rules haveextended the implementation date for certain facilities that are subject to these standards. The U.S. Department of Energy is conducting an12investigation of practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Morerecently, 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 orother regulatory mechanisms.Almost all of our hydraulic fracturing operations are conducted on vertical wells. The fracture treatments on these wells are much smaller and utilizemuch 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 ofour leasehold acreage is currently held by production from existing wells. Therefore, fracturing is not currently required to maintain this acreage but it will berequired 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 bystate and federal regulators, which conduct many inspections during operations that include hydraulic fracturing. We minimize the use of water and disposeof the produced water into approved disposal or injection wells. We currently do not intentionally discharge water to the surface.Air EmissionsThe 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 obtainpre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain andstrictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has thepotential 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-relatedissues, we do not believe that such requirements will have a material adverse effect on our operations. For example, on August 16, 2012, the EPA publishedfinal regulations under the Clean Air Act that, among other things, required additional emissions controls for natural gas and NGLs production, includingNew Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOC”), and a separate set of emission standardsto address hazardous air pollutants frequently associated with such production activities. The final regulations required the reduction of VOC emissions fromnatural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured afterJanuary 1, 2015. For well completion operations that occurred at such well sites before January 1, 2015, the final regulations allow operators to capture anddirect flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establishedspecific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements couldincrease our costs of development and production, though we do not expect these requirements to be any more burdensome to us than to other similarlysituated companies involved in oil and natural gas exploration and production activities.Climate ChangeIn December 2009, the EPA published its findings that emissions of carbon dioxide, or CO2, methane, and other greenhouse gases, or “GHG”, present adanger to public health and the environment. Based on these findings, the EPA began adopting and implementing regulations that restrict emissions of GHGunder existing provisions of the federal Clean Air Act. These regulations include requirements to regulate emissions of GHG from motor vehicles, certainrequirements for construction and operating permit reviews for GHG emissions from certain large stationary sources, rules requiring the reporting of GHGemissions from specified large GHG emission sources including operators of onshore oil and natural gas production and rules requiring so-called greencompletions of natural gas wells for wells constructed after January 2015. In addition, in May 2016, the EPA issued new regulations that set methane andVOC 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 pendingreconsideration of the rule. The Paris Agreement, which was created by the United Nations Framework Convention on Climate Change, entered into force onNovember 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 Agreementon June 1, 2017.We are currently monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. Data collected from our initialGHG monitoring activities indicated that we do not currently exceed the threshold level of GHG emissions triggering a reporting obligation. To the extent weexceed the applicable regulatory threshold level in the future, we will report the emissions beginning in the applicable period. Also, the U.S. Congress hasfrom time to time considered legislation to reduce emissions of GHG and almost one-half of the states, either individually or through multi-state regionalinitiatives, already have begun implementing legal measures to reduce emissions of GHG. The adoption and implementation of any regulations imposingreporting obligations on, or limiting emissions of GHG from, our equipment and operations could require us to incur significant costs to reduce emissions ofGHG associated with operations or could adversely affect demand for our production.13The EPA has also finalized regulations to reduce carbon dioxide emissions from the utility power sector, commonly referred to as the Clean PowerPlan, which, if implemented, could reduce the demand for fossil fuels. The implementation of this rule has been stayed pending judicial review, and inOctober 2017, the EPA proposed the repeal of the Clean Power Plan.National Environmental Policy ActOil exploration, development and production activities that are located on federal lands or have a federal “nexus” are subject to the NationalEnvironmental Policy Act, as amended, (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actionshaving the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment thatanalyzes the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impactstatement that may be made available for public review and comment. Future or proposed exploration and development plans on federal lands, governmentalpermits or authorizations that are subject to the requirements of NEPA may be required. This process has the potential to delay the development of oilprojects.Endangered Species ActThe federal Endangered Species Act (“ESA”) may restrict activities that affect endangered or threatened species. Federal agencies are required toensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their criticalhabitat. The designation of previously unidentified endangered or threatened species habitats could cause us to incur additional costs or become subject tooperating 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 onSeptember 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Actover a period of six years. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incurincreased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverseimpact on our ability to develop and produce our reserves.OSHAWe are subject to the requirements of the federal Occupational Safety and Health Act, as amended, (“OSHA”), and comparable state statutes whosepurpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Rightto Know Act and implementing regulations, and similar state statutes and regulations require that we organize and/or disclose information about hazardousmaterials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. Webelieve 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 IndustryGeneralVarious aspects of our oil and natural gas operations are subject to extensive and frequently changing regulation as the activities of the oil and naturalgas 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 transportationservice, 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 oilpipelines 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 underthe Energy Policy Act of 2005. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-pricecontrols affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas and all sales of crude oil, condensate andNGLs 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 toprevent market manipulation in oil and energy futures markets, respectively. Together with FERC, these agencies have imposed broad rules and regulationsprohibiting fraud and manipulation in oil and natural gas markets and energy futures markets. We are also subject to various reporting requirements that aredesigned to facilitate transparency and prevent market manipulation. Failure to comply with such market rules, regulations and requirements could have amaterial adverse effect on our business, results of operations, and financial condition.14Oil and NGLs Transportation RatesOur sales of crude oil, condensate and NGLs are not currently regulated and are transacted at market prices. In a number of instances, however, theability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under theICA 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. Interstatetransportation 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 in1992, 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 alternativeforms 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 dependenton pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. Such pipelines may besubject to regulation by state regulatory agencies with respect to safety, rates and/or terms and conditions of service, including requirements for ratable takesor non-discriminatory access to pipeline services. The basis for intrastate regulation and the degree of regulatory oversight and scrutiny given to intrastatepipelines varies from state to state. Many states operate on a complaint-based system and state commissions have generally not initiated investigations of therates or practices of liquids pipelines in the absence of a complaint.Regulation of Oil and Natural Gas Exploration and ProductionOur exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations includerequiring 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 wellsare drilled. Many states also have statutes or regulations addressing conservation of oil and natural gas resources, including provisions for the unitization orpooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing ofsuch wells.Oklahoma allows forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. Insome instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, stateconservation laws establish maximum rates of production from oil wells generally prohibit the venting or flaring of natural gas and impose requirementsregarding 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 thenumber 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 aproduction tax and an excise tax for oil and natural gas properties. Additionally, production tax rates vary by state. States do not regulate wellhead prices orengage 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 tocomply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the sameregulatory 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 relateto resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.Pipeline SafetyWhile we do not own pipelines subject to safety regulation, we rely on such pipelines to deliver our production. Federal and state safety regulationshave become increasingly more stringent over time and could affect the availability and cost of pipeline transportation to us.EmployeesThe officers of our general partner manage our operations and activities. Neither we, our subsidiaries, nor our general partner have employees. Ourgeneral partner has entered into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating will perform services forus, including the operation of our properties. Mid-Con Energy Operating has over 70 employees performing services for our operations and activities. Webelieve that Mid-Con Energy Operating has a satisfactory relationship with these employees.15OfficesIn addition to our oil and natural gas properties discussed above, we lease corporate office space in Tulsa, Oklahoma, and lease field office space inAbilene, Texas. Our affiliate, Mid-Con Energy Operating, maintains a number of field office locations. We believe that our existing office facilities areadequate to meet our needs for the immediate future.Financial InformationWe operate our business as a single segment. Additionally, all of our properties are located in the United States and all of the related reserves arederived from properties located in the United States. Our financial information is included in the consolidated financial statements and the related notesincluded in Item 8. “Financial Statements and Supplementary Data.”Available InformationOur 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 furnishedpursuant 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 atwww.midconenergypartners.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. Thesedocuments 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 PublicReference Room at 100 F Street, NE, Washington, DC, 20549. No information from either the SEC’s website or our website is incorporated herein byreference. ITEM 1A.RISK FACTORSLimited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subjectare 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 BusinessWe may not have sufficient cash available to make quarterly distributions on our units following the establishment of cash reserves and payment ofexpenses, 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 requirethe 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 PartnershipAgreement, the amount of cash available for distributions will be reduced by our operating expenses and the amount of any cash reserves established by ourgeneral partner to provide for future operations, future capital expenditures, including development of our oil and natural gas properties, future debt servicerequirements and future cash distributions to our unitholders. The amount of cash that we distribute to our unitholders will depend principally on the cash wegenerate 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 PreferredUnit 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 ClassB Preferred Unit distributions have been paid in full in cash.16If we do not maintain certain financial covenants under our revolving credit facility we may be deemed in breach, entitling our lenders to accelerate theamounts 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 cashflow generation of our business, including but not limited to, future oil and natural gas prices, sales from produced oil and natural gas volumes, and cashoperating expenses, could result in our breaching certain financial covenants under the revolving credit facility, which would constitute a default under therevolving 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 waiverfrom the Administrative Agent and the Lenders under our revolving credit facility and are now in compliance with the leverage calculation ratio, there can beno 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 waivershould 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 thewellhead 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 relativelyminor 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 andother 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 relevantbenchmark prices, such as the NYMEX-WTI, that are used for calculating hedge positions. These discounts, if significant, could similarly adversely affect ourcash 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 commodityprices. However, we have not been able to sustain those distributions. In October 2015, the Board elected to suspend quarterly cash distributions on ourcommon 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 rangedfrom 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 pricemovements with any certainty.17If commodity prices decline from current levels, production from some of our producing or development projects may become uneconomic and cause writedowns 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 severeor prolonged, a significant portion of such projects may become uneconomic. As producing or development projects become uneconomic, our reserveestimates will be adjusted downward, which could negatively impact our borrowing base under our current revolving credit facility and our ability to fundour operations.Deteriorating commodity prices may cause us to recognize impairments in the value of our oil and natural gas properties. We recognized $25.0 millionin non-cash impairment expense for the year ended December 31, 2017. In addition, if our estimates of development costs increase, production data factorschange 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 andnatural gas properties for additional impairments. We may incur impairment in the future which could have a material adverse effect on our results ofoperations 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 ourfinancial condition.Our hedging strategy is to enter into commodity derivative contracts covering a portion of our near-term estimated oil production. The prices at whichwe 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 enterinto 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 ofour estimated future production, and we therefore retain the risk of a price decrease on our volumes which we are precluded from securing with commodityderivative 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 enterinto 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 cashflows from operation.Our hedging strategy may limit our ability to realize cash flows from commodity price increases. Many of our commodity derivative contracts requireus to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases inoil prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in productiondue 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 theunderlying 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 thefinancial markets could lead to a sudden decrease in a counterparty’s liquidity, which could impair its ability to perform under the terms of the commodityderivative contract and, accordingly, prevent us from realizing the benefit of the commodity derivative contract. Because we conduct our hedging activitiesexclusively 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 contractcounterparties have come under increasing governmental oversight and regulations in recent years. Although we cannot predict the ultimate impact of theselaws and the related rulemaking, some of which is ongoing, existing or future regulations may adversely affect the cost and availability of our hedgingarrangements, 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 fromoperations.Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and otherfactors. Our future oil and natural gas reserves and production and, therefore, our cash flows from operations and ability to resume making distributions onour common units are highly dependent on our success in economically finding or acquiring recoverable reserves and efficiently developing our currentreserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline ratemay change when we make acquisitions. We18may not be able to develop, find or acquire additional reserves to replace our current and future production on economically acceptable terms, which wouldadversely 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 gasreserves. 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 obtaindebt 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 otherreason. If cash generated by operations or availability under our revolving credit facility is not sufficient to meet our capital requirements, the failure toobtain additional financing could result in a curtailment of our operations relating to advancement of our development projects, which in turn could lead to adecline 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 canadversely 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 muchoil 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 andsuspension 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 failto 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 mayemploy other secondary or tertiary recovery methods in our operations. The additional production and reserves attributable to the use of secondary recoverymethods and of tertiary recovery methods are inherently difficult to predict. If our recovery methods do not result in expected production levels, we may notrealize 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 aredependent on our ability to hydraulically fracture the producing formations. We engage third-party contractors to provide hydraulic fracturing services andgenerally enter into service orders on a job-by-job basis. Some service orders limit the liability of these contractors. Hydraulic fracturing operations can resultin surface spillage or, in rare cases, the underground migration of fracturing fluids. Any such spillage or migration could result in litigation, government finesand penalties or remediation or restoration obligations. Our current insurance policies provide some coverage for losses arising out of our hydraulic fracturingoperations. However,19these policies may not cover fines, penalties or costs and expenses related to government-mandated cleanup activities, and total losses related to a spill ormigration could exceed our per occurrence or aggregate policy limits. Any losses due to hydraulic fracturing that are not fully covered by insurance couldhave 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 inthese 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 levelsand operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing ofdevelopment 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 reserveswhich 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 ourestimated proved oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from ourestimated 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 thencurrent prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future netcash 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 gasindustry 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 acquisitionwe complete, and any adverse conditions or developments related to any such acquisition may have a negative impact on our operations and financialcondition. 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 orrestructuring 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 variousinterpretations.20Also, our reviews of properties acquired from third parties (as opposed to the Mid-Con Affiliate) may be incomplete because it generally is not feasibleto perform an in-depth review of the individual properties involved in each acquisition, given the time constraints imposed by most sellers. Even a detailedreview of the properties owned by third parties and the records associated with such properties may not reveal existing or potential problems, nor will such areview permit us to become sufficiently familiar with such properties to assess fully the deficiencies and potential issues associated with such properties. Wemay not always be able to inspect every well on properties owned by third parties, and environmental problems, such as groundwater contamination, are notnecessarily 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 adversedevelopment 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 andproduction 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 significantcustomers, we believe that we could identify substitute customers to purchase the impacted production volumes. However, if any of our customersdramatically 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 willcontinue to be, marketed by our affiliate, Mid-Con Energy Operating. By selling a substantial majority of our current production to a small concentration ofcustomers we believe that we have obtained and will continue to receive more favorable pricing than would otherwise be available to us if smaller amountshad been sold to several purchasers based on posted prices. To the extent these significant customers reduce the volume of oil and natural gas they purchasefrom 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 fromoperations 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 havea 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 fundtheir operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were todetermine 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, wewould 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 makedistributions 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 proposedunit area to consent to a unitization plan before the relevant regulatory body will issue a unitization order. Mid-Con Energy Operating may be required todedicate significant amounts of time and financial resources to obtaining consents from other owners and the necessary approvals from the state and federalregulatory agencies. These consents and approvals may also delay our ability to begin developing our new waterflood projects and may prevent us fromdeveloping 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 maymigrate out of our areas of operations and into neighboring properties, including properties whose mineral rights owners have not consented to participate inour operations. This may result in litigation in which the owners of these neighboring properties may allege, among other things, a trespass and may seekmonetary 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 ofoperations.The oil and natural gas industry is intensely competitive, and we compete with companies that possess and employ financial, technical and personnelresources substantially greater than ours. These companies may be able to pay more for properties and evaluate, bid for and purchase a greater number ofproperties than our financial, technical or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future willdepend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our largercompetitors not only drill for and produce oil and21natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. In addition, there issubstantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue developmentactivities despite the currently depressed oil price environment and to absorb the burden of present and future federal, state, local and other laws andregulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial conditionand 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 lyingcontiguous or adjacent to or adjoining our interests could take actions, such as drilling additional wells, which could adversely affect our operations. When anew well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (andpotentially 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 ourlenders 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 requiresus to comply with customary financial covenants and specified financial ratios. If market or other economic conditions deteriorate, our ability to comply withthese covenants may be impaired. If we violate any provisions of our revolving credit facility that are not cured or waived within specific time periods, asignificant portion of our indebtedness may become immediately due and payable, we could be prohibited from making distributions to our unitholders inthe 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 theseaccelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable torepay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets. Further, the terms of our credit agreement requirethe 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 estimatedvalue of our oil and natural gas properties and our commodity derivative contracts, as determined by our lenders in their sole discretion. The borrowing baseis subject to redetermination on a semi-annual basis and more frequent redetermination in certain circumstances. If our lenders were to decrease our borrowingbase to a level below our then outstanding borrowings, the amount exceeding the revised borrowing base could become immediately due and payable. Thenegative redetermination of our borrowing base could adversely affect our business, results of operations, financial condition and our ability to makedistributions to our unitholders. Furthermore, in the future, we may be unable to access sufficient capital under our revolving credit facility as a result of anydecrease 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 debtthat 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 debtobligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors willaffect our future financial performance, and, as a result, our ability to generate cash flows from operations and to service our debt obligations. Many of thesefactors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of ourcompetitors, 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, suchas: •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. Ourinability to generate sufficient cash flows to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our ability toservice our indebtedness and our business, financial condition and results of operations.22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 couldresult in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmentalpollution, impairment of our operations and substantial revenue losses. The location of our wells and other facilities near populated areas, includingresidential 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 risksthat 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 beavailable in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to weather and adverseeconomic 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 ofinsurance we would otherwise have obtained prior to these market changes, and we cannot be sure the insurance coverage we do obtain will not contain largedeductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and under-insured events and delay in thepayment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to makedistributions 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 couldinterfere 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 transportationmethods, 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 suchsystems, tanker truck availability and extreme weather conditions. Also, the shipment of our oil on third party pipelines may be curtailed or delayed if it doesnot meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to severalmonths. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significantcurtailment 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 ofoil production and transportation, and pipeline safety, as well by general economic conditions and changes in supply and demand. In addition, the thirdparties on whom we rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner orfeasibility 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 gasthat 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 theenvironment. Based on these findings, the EPA began adopting and implementing regulations that restrict emissions of GHG under existing provisions of thefederal Clean Air Act, including requirements to reduce emissions of GHG from motor vehicles, requirements associated with certain construction andoperating permit reviews for GHG emissions from certain large stationary sources, reporting requirements for GHG emissions from specified large GHGemission sources, including certain owners and operators of onshore oil and natural gas production and rules requiring so-called “green completions” ofnatural gas wells constructed after January 2015. We are currently monitoring GHG emissions from our operations in accordance with the GHG emissionsreporting rule. Data collected from our initial GHG monitoring activities indicated that we do not exceed the threshold level of GHG emissions triggering areporting obligation. To the extent we exceed the applicable regulatory threshold level in the future, we will report the emissions beginning in the applicableperiod. 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 individuallyor through multi-state regional initiatives, have already begun implementing legal measures to reduce emissions of GHG. In March 2016, the EPA issued newregulations 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 certainrequirements of this rule pending reconsideration of the rule. In addition, under the Paris Agreement, which went into effect on November 4, 2016, the UnitedStates is required to establish increasingly stringent nationally determined contributions to mitigate climate change. The United States announced itsintention to withdraw from the Paris Agreement on June 1, 2017. The adoption and implementation of any regulations imposing reporting obligations on, orlimiting emissions of GHG from, our equipment and operations could require us to incur significant costs to reduce emissions of GHG associated withoperations or could adversely affect demand for our production.23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 withthe energy industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation that could lead tooperational delays, increase our operating and compliance costs or otherwise adversely affect our operations. To date, these regulations have not adverselyimpacted 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 andnatural gas wastewater disposed in such wells, restricting disposal well locations, or by requiring us to shut down disposal wells, could have a materialadverse 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 operatingcosts.In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission and storage operations to regulation underthe New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA’s final ruleincludes 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 anddistribution of required emissions reduction technology. As an example, until December 31, 2014, owners and operators of hydraulically fractured gas wellscould either flare their emissions or use emissions reduction technology called “green completions” technologies already deployed at wells. On or afterJanuary 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 moreburdensome 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 productionactivities. These costs and liabilities could arise under a wide range of federal, state, tribal and local environmental and safety laws and regulations, includingregulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations mayresult 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 maydelay or interrupt our operations and limit our growth and revenue. Claims for damages to persons or property from private parties and governmentalauthorities 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 othersor for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations orenforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover theresulting costs through insurance or increased revenues, our ability to make cash distributions to our unitholders could be adversely affected. For a detaileddiscussion 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 operatingrestrictions 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 tightconventional formations, including many of those that we complete and produce. The hydraulic fracturing process involves the injection of water, sand andchemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil andnatural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under thefederal Safe Drinking Water Act and has published guidance documents related to this regulatory authority. In addition, from time to time, Congress hasconsidered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturingprocess. Many states in which we operate have adopted rules requiring well operators to publicly disclose certain information regarding hydraulic fracturingoperations, including the chemical composition of any liquids used in the hydraulic fracturing process. Generally, certain proprietary information may beexcluded from an operator’s disclosure. Additionally, some states and local authorities have adopted, and other states are considering adopting, regulationsthat could restrict hydraulic fracturing in certain circumstances. In the event that24new or more stringent federal, state or local legal restrictions are adopted in areas where we operate, we could incur potentially significant added costs tocomply 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 fracturingpractices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated withhydraulic fracturing. The EPA has completed a study of the potential environmental effects of hydraulic fracturing on drinking water resources and issued itsfinal report in December 2016. The report concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances andidentified conditions under which the impacts may be more frequent or severe. In June 2016, the EPA published final pretreatment standards for oil and gasextraction sources to ensure that wastewater from hydraulic fracturing activities is not sent to publicly owned treatment works. Subsequent rules haveextended the implementation date for certain facilities that are subject to these standards. The U.S. Department of Energy is conducting an investigation ofpractices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. More recently, therehave been reports linking the injection of produced fluids from hydraulic fracturing to earthquakes. These ongoing or proposed studies, depending on theirdegree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking WaterAct or other regulatory mechanisms. Any additional level of regulation could lead to operational delays or increased operating costs which could result inadditional regulatory burdens that could make it more difficult to perform hydraulic fracturing and would increase our costs of doing business, and couldadversely 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 resultscould also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering withor manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk operational system flaws, employeetampering 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 computerprograms to help run our financial and operations sectors, including to estimate quantities of oil and natural gas reserves, process and record financial andoperating data, analyze seismic and drilling information, and to communicate with our employees and third-party partners. Any future cyber security attacksthat affect our facilities, our customers and any financial data could lead to data corruption, communication interruption, or other disruptions in ourdevelopment operations or planned business transactions, any of which could have a material adverse effect on our business. In addition, security cyberattacks on our customer and employee data may result in a financial loss and may negatively impact our reputation. Third-party systems on which we relycould also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage orotherwise have an adverse effect on our financial results. Further, as cyber security attacks continue to evolve, we may be required to expend significantadditional 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 UsOur general partner controls us, and the Founders, our Mid-Con Affiliate and Yorktown own an approximate 20% interest in us. They have conflicts ofinterest 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 andJeffrey R. Olmstead. As of December 31, 2017, the Founders, our Mid-Con Affiliate and Yorktown own an approximate 20% interest in us. Although ourgeneral 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 aduty 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 arealso 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, theMid-Con Affiliate. Additionally, one of the directors of our general partner is a principal with Yorktown. As a result of these relationships, conflicts of interestmay 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 andour 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 overthe 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 generalpartner with contractual standards governing its duties and also restricts the remedies available to our unitholders for actions that, without theselimitations, might constitute breaches of fiduciary duty. By purchasing common25 units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other dutiesunder applicable law; •neither our Partnership Agreement nor any other agreement requires the Mid-Con Affiliate and Yorktown or their respective affiliates (otherthan our general partner) to pursue a business strategy that favors us. The officers and directors of the Mid-Con Affiliate and Yorktown and theirrespective 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 futureacquisition 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 Affiliateand are compensated for those services rendered; •our general partner determines the amount and timing of our development operations and related capital expenditures, asset purchases andsales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other businesseswith which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed tounitholders; •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 orentering 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 beindemnified 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 commonunits; •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. Themanagement 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 andoperational services to us. Mid-Con Energy Operating provides substantially similar services and personnel to the Mid-Con Affiliate and, as a result, may nothave 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 similarservices to these other entities. Additionally, Mid-Con Energy Operating may make internal decisions on how to allocate its available resources and expertisethat 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 thatMid-Con Energy Operating favor us over these other entities in providing its services. If the employees of Mid-Con Energy Operating do not devotesufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholdersmay be reduced.Increases in interest rates could adversely affect our business, results of operations, cash flows from operations and financial condition, and cause adecline 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 increasesin interest rates. As a result, our business, results of operations and cash flows may be adversely affected by significant increases in interest rates. Further, anincrease 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 commonunits 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 unlessfull 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 allaccumulated and unpaid distributions have been declared and paid on the Preferred Units. In26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 transactionbefore the holders of the common units. The payment of the liquidation preference could result in common unitholders not receiving any consideration if wewere to liquidate, dissolve or wind-up, either voluntarily or involuntarily. Additionally, the existence of the liquidation preference may reduce the value ofthe 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 financefuture 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, subjectto certain exceptions, the affirmative vote or consent of the holders of at least a majority of the outstanding Preferred Units, voting together as a separateclass, will be necessary for effecting or validating, among other things: (i) any action to be taken that adversely affects any of the rights, preferences orprivileges of the Preferred Units, (ii) amending the terms of the Preferred Units, (iii) the issuance of any additional Preferred Units or equity security senior orpari 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 ortrade payables arising in the ordinary course of business) or (v) lift the suspension of the at-the-market offering program. These restrictions may adverselyaffect 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 commonunits 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-monthanniversary 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 APreferred 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 Unitsfor cash. In addition, in connection with a change of control of the Partnership, holders of Preferred Units may elect to have their Preferred Units convertedinto 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 PreferredUnits, 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, ifholders of converted Preferred Units dispose of a substantial portion of such common units in the public market, whether in a single transaction or series oftransactions, it could adversely affect the market price for our common units. These sales, or the possibility that these sales may occur, could make it moredifficult 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 cashexpenditure 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 suchredemption.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 requirementsregarding 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 andnatural 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 statethereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parentcorporation 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 asubstantial 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 controlin 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 EligibleHolder 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 ofa promissory note, as determined by our general partner.27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 whichour 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 generalpartner or its Board of Directors. The Board of Directors of our general partner, including the independent directors, is chosen entirely by Charles R. Olmsteadand Jeffrey R. Olmstead, the voting members of our general partner, and not by our unitholders. Unlike publicly traded corporations, we do not conductannual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As aresult 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 thetrading 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 ourgeneral 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 theunitholders. Furthermore, our Partnership Agreement does not restrict the ability of the Founders from transferring all or a portion of their ownership interestsin 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 ourgeneral 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 alignedwith 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 woulddilute 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 ourunitholders. 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 followingeffects: •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 itsaffiliates, the holders of our Preferred Units and Yorktown, which may limit the ability of significant common unitholders to influence the manner ordirection of management.Our Partnership Agreement restricts unitholders’ voting rights by providing that any common units held by a person, entity or group owning 20% ormore of any class of common units then outstanding, other than our general partner and its affiliates, the holders of our Preferred Units, Yorktown and theirtransferees 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 wellas 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 generalpartner, 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 perceptionthat 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 capitalthrough the sale of additional common units.28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 ofthe partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in anumber of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearlyestablished 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’spartnership statute; or •a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our PartnershipAgreement 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 wrongfullyreturned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions tounitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interestsand liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for aperiod of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of thedistribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. This requirement could apply to quarterlydistributions made before suspension and to future distributions, in the event we elect to reinstate the distributions. A purchaser of common units whobecomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser ofcommon 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 UnitholdersOur 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 towhom we will allocate taxable income, which could be different in amount than the cash we distribute, our unitholders are required to pay any federal incometaxes 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 unitholdersmay 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 unitholderswithout a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, unitholdersmay 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 acorporation, 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 taxpurposes.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 wesatisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet thequalifying income requirement, or a change in current law, could cause us to be treated as a corporation for federal income tax purposes or otherwise subjectus 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 rateand would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions whichwould 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 forU.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 asa corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in amaterial reduction in the anticipated cash flows and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.29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 ourunitholders.Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits andother reasons, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise andother forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders and, therefore, negativelyimpact 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 changesand 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 byadministrative, legislative or judicial interpretation at any time. For example, from time to time the U.S. President and members of the U.S. Congress proposeand 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 ofqualifying income for publicly traded partnerships by providing industry-specific guidance. We believe the income that we treat as qualifying incomesatisfies 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 applicableto both individuals and entities, including changes to the tax rate on an individual or other non-corporate unitholder’s allocable share of certain income froma publicly traded partnership. The TCJA is complex and lacks administrative guidance, thus, the impact of certain aspects of its provisions on us or aninvestment 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 notbe 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 taxpurposes or otherwise adversely affect us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any suchchanges 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 willreduce 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 someor 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 forour 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 generalpartner 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 intheir 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, ifany, 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 greaterthan 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 andIntangible Drilling Costs deduction recapture. In addition, because the amount realized may include a unitholder’s share of our non-recourse liabilities, theymay 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 taxableyear. However, under the TCJA, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of ourbusiness interest income plus 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed withoutregard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deductionallowable for depreciation, depletion or amortization. Any interest disallowed may be carried forward and deducted in future years by the unitholder from hisshare 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 forbusiness interest for such future taxable year, subject to certain restrictions. 30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. personsraises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs andother retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December31, 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 isengaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately withrespect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning afterDecember 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxableincome 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, whichcould 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 amortizationpositions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect theamount 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 couldhave 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 ourunits 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 couldchange 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 ourunits 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 publiclytraded partnerships to use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, these regulations donot specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge our proration method or newTreasury 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 havingdisposed 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 theloan 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 arethe 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 apartner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during theperiod 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 cashdistributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners andavoid 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 applicablebrokerage 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 challengethese 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 ourassets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimatesourselves 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 challengethese 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 toour 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 resultin 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 weoperate 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, unincorporatedbusiness taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now orin 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 andpay 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 thoserequirements. We own property and conduct business in many states, some of which impose a personal income tax on individuals and impose an income taxon corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose apersonal 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 allU.S. federal, state and local tax returns.ITEM 1B.UNRESOLVED STAFF COMMENTSNone.ITEM 2.PROPERTIESOil and Natural Gas ReservesInternal Controls Relating to Reserve EstimatesWe maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used inour reserves estimation process. Our internal controls over the recording of reserves estimates require reserve estimates to be in compliance with the SECrules, regulations, definitions and guidance. Our proved reserves are estimated at the well, lease, or unit level and compiled for reporting purposes by ourreservoir engineering staff. Internal evaluations of our reserves are maintained in a secure reserve engineering database. Reserves are reviewed internally byour 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. Tofacilitate their audit of our reserves, we provide CG&A with any information they may request, including all of our reserve information as well as geologicmaps, well logs, production tests, material balance calculations, well performance data, operating procedures, LOE, product pricing, production taxes andrelevant 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 ReservesUnder the SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimatedwith reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operatingmethods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actuallyrecovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual productionfrom projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliabletechnology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to providereasonably 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 thathave been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our provedreserves 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 usingappropriate decline curves or other performance relationships. Reserves attributable to producing properties with limited production history and forundeveloped locations are estimated using performance from analogous properties in the surrounding area and geologic data to assess the reservoircontinuity. These properties were considered to be analogous based on production performance from the same formation and similar completion techniques.Qualifications of Responsible Technical PersonsCG&A is an independent oil and natural gas consulting firm. No director, officer, or key employee of CG&A has any financial ownership in thePartnership, the Mid-Con Affiliate, Mid-Con Energy Operating or any of their respective affiliates. The compensation paid to CG&A for the audit is notcontingent upon the results obtained and reported. The engineering audit presented in the CG&A32report was overseen by W. Todd Brooker, President. Mr. Brooker has been a Petroleum Consultant for CG&A since 1992, became Senior Vice President in2011 and President in 2017. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies andacquisition and divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projectsin both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methanefields, 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 registeredprofessional 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 previouslyserved 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 ReservesThe following table presents our estimated net proved oil and natural gas reserves as of December 31, 2017, based on reserve reports prepared by ourreservoir engineering staff and audited by CG&A. Net OilMBbls Net GasMMcf TotalNet 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, heldconstant 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 Bblfor 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 $2.27per 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 estimatingunderground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality ofavailable data, engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil that are ultimatelyrecovered. For a discussion of risks associated with internal reserve estimates, see Item 1A. “Risk Factors - Risks Related to Our Business.” Our estimatedproved reserves and future production rates rely on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates orunderlying 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. Thestandardized measure amounts should not be construed as the current market value of our estimated oil reserves. The 10% discount factor used to calculatestandardized measure, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. Thepresent 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 ReservesWith respect to PUDs, we have established a development plan approved by the Vice President of Development of Mid-Con Energy Operating thatwill result in converting the PUDs within five years from the initial disclosure of the reserves and the associated development capital requirements are equalto 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 PUDsfrom our proved reserves disclosures. None of our proved undeveloped reserves as of December 31, 2017, have remained undeveloped for more than fiveyears 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 pricingforecasts, recent drilling results and waterflood responses. None of our PUDs at December 31, 2017, are scheduled to be developed on a date more than fiveyears from the date the reserves were initially booked as proved undeveloped. Consistent with the typical waterflood response time range of 6-18 monthsfrom initial development, the transfer of PUDs to the proved developed category is attributable to development costs incurred. During 2017, our capitalexpenditures for development (drilling, recompletion and conversion to injection) were $7.4 million. Based on our current expectations of cash flows, weexpect 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 provedundeveloped 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 normallyobtained 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 Bblfor 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 of60 MBoe during the year ending December 31, 2017. We saw continued positive oil production responses to water injection in our Texas core area from bothexisting 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 increaseof 343 MBoe in PUDs.Extensions and discoveries of proved undeveloped reserves. These were additions to PUDs that resulted from successful offset drilling in our Texascore 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 resultedin a decrease in PUDs of 701 MBoe.Developed and Undeveloped AcreageThe following table sets forth information relating to our leasehold acreage. Acreage related to royalty, overriding royalty and other similar interestswere 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 1,240All of the PUDs in the Oklahoma core area are related to new drilling or recompletion activities within currently producing areas of our developedacreage and represent in-fill or reduced spacing activity; therefore, all acreage is considered developed.34Drilling ActivitiesFor information with respect to wells drilled and completed for the years ended December 31, 2017, and 2016, see Item 1. “Business - DrillingActivities”.Productive WellsFor 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 PropertiesPrior to completing an acquisition of producing oil properties, we perform title reviews on significant leases, and depending on the materiality ofproperties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significantportion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record correctiveassignments 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 drillingoperations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent titleopinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generallywill 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 andrestrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and otherburdens, 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 interferewith 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 permitsfrom public authorities and private parties for us to operate our business.ITEM 3.LEGAL PROCEEDINGSAlthough 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 notcurrently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, orcontemplated to be brought against us, under the various environmental protection statutes to which we are subject. No amounts have been accrued atDecember 31, 2017.ITEM 4.MINE SAFETY DISCLOSURESNot applicable.35PART IIITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OFEQUITY SECURITIESOur common units are listed under the symbol “MCEP” on the NASDAQ. At the close of business on February 19, 2018, based upon informationreceived from our transfer agent and brokers and nominees, we had 37 limited partner unitholders of record. This number does not include owners for whomcommon units may be held in “street” names. The daily high and low closing prices per common unit for the period from January 1, 2017, throughDecember 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 $1.93Cash Distributions to UnitholdersIn October 2015, prolonged declines in commodity prices prompted us to suspend cash distributions to common unitholders in an effort to preserveliquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-term value for our unitholders. There isno assurance as to future cash distributions since they are dependent upon our projections for future earnings, cash flows, capital requirements, financialconditions 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 PolicyOur 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 operatingexpenses) 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 thenext 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 thequarter.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 PlansSee Item 11. “Executive Compensation - Long-Term Incentive Program” for information regarding our equity compensation plans as of December 31,2017.36Sales of Unregistered SecuritiesNone.Issuer Purchases of Equity SecuritiesNone.ITEM 6.SELECTED FINANCIAL DATAAs 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 OPERATIONSThe 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.OverviewMid-Con Energy Partners is a publicly held limited partnership formed in July 2011 that engages in the ownership, acquisition and development ofproducing oil and natural gas properties in North America, with a focus on EOR. Our properties are located primarily in the Mid-Continent and Permian Basinregions of the United States in our Oklahoma and Texas core areas. In 2017, we sold all of our Southern Oklahoma properties. Our properties primarily consistof 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 aBoe basis. As of December 31, 2017, we operated 100% of our properties through our affiliate, Mid-Con Energy Operating, and 64% of our net provedreserves were being produced under waterflood, in each instance on a Boe basis. Our average net production for the month ended December 31, 2017, was3,163 Boe/d and our total estimated proved reserves had a reserve-to-production ratio of 17 years.Recent DevelopmentsWheatland AcquisitionOn June 1, 2017, we acquired multiple oil and natural gas properties located in Oklahoma County and Cleveland County, Oklahoma for cashconsideration of $4.1 million, after preliminary post-closing purchase price adjustments. The effective date of the acquisition was April 1, 2017. See Note 3 tothe Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for additional information.Southern Oklahoma DivestitureOn December 22, 2017, we completed the sale of properties in the Southern Oklahoma region (the “Southern Oklahoma divestiture”) for cash proceedsof $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 December22, 2017. See Note 3 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for additionalinformation.Nolan County DivestitureOn January 9, 2018, we completed the sale of certain Permian oil and natural gas proved properties in Nolan County, Texas (the “Nolan Countydivestiture”), for cash consideration of $1.6 million, subject to customary post-closing sale price adjustments. The effective date of the divestiture wasNovember 1, 2017.House Creek AcquisitionOn January 16, 2018, we acquired multiple oil and natural gas properties located in Campbell County, Wyoming (“House Creek”), for cashconsideration 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 OfferingOn 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. ThePartnership used a portion of the proceeds from the offering to fund the acquisition of certain properties in Campbell and Converse Counties, Wyoming, andany 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 annualrate 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 andprior 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 representinglimited 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 anyportion 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 tocommon units on a one-for-one basis.Pine Tree AcquisitionOn January 31, 2018, we acquired multiple oil and natural gas properties located in Campbell and Converse Counties, Wyoming (“Pine Tree”), forcash consideration of $8.6 million, subject to customary post-closing sale price adjustments. The effective date of the acquisition was September 1, 2017. Thepurchase price was funded by the Class B Preferred Unit offering described above.Revolving Credit FacilityDuring the quarter ended September 30, 2017, we were not in compliance with our leverage ratio calculation. On November 10, 2017, the Partnershipreceived a waiver from the Administrative Agent and the Lenders of our revolving credit facility waiving the noncompliance through December 15, 2017. OnDecember 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 NolanCounty 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 extendedthe 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 thePartnership’s failure to maintain the required leverage ratio for the quarter ended September 30, 2017. The amendment also required the Partnership to have aminimum liquidity of 20% prior to making any distributions to the Preferred Unitholders.Reduction of DebtAs of February 28, 2018, we had reduced outstanding debt by $31.8 million since December 31, 2016. Funds for debt repayment were provided by theSouthern Oklahoma and Nolan County divestitures, remaining proceeds from the Class B Preferred Unit offering in excess of the Pine Tree acquisition andcash flows from operations.DistributionsIn 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 January31, 2018, the Partnership announced that the Board declared a Class A Preferred Unit cash distribution for the third and fourth quarters of 2017, according toterms 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 writtenconsent from our lenders is required in order to reinstate common unit distributions and also prohibits us from making common unit cash distributions if anypotential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution. Management and the Board willcontinue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determining future distributions. The suspension of common unit cashdistributions is designed to preserve liquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-termvalue for our unitholders.Appointment and Departure of Certain OfficersMr. 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, andserved in an advisory role until November 30, 2017.Business EnvironmentThe 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 andnatural gas may fluctuate widely. Sustained periods of low prices for oil and natural gas could materially and adversely affect our financial position, ourresults of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Our average sales price perbarrel 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 $43.47Our 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 commodityderivative 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 oilproduction over a fixed period of time. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contractswhen 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 managementactivities exclusively with participant lenders in our revolving credit facility. We have entered oil commodity derivative contracts covering a portion of ouranticipated 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 formationdecreases. 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 isprimarily 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, obtainregulatory 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-termoperations. Our future cash flows from operations are impacted by our ability to manage our overall cost structure.How We Evaluate Our OperationsOur primary business objective is to manage our oil and natural gas properties for the purpose of generating stable cash flows, which will providestability and, over time, growth of distributions to our unitholders. The amount of cash that we can distribute to our unitholders depends principally on thecash 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 industryanalysts, investors, lenders, rating agencies and others, to assess the cash flow generated by our assets, without regard to financing methods, capital structureor historical cost basis and our ability to incur and service debt and fund capital expenditures. In addition, management uses Adjusted EBITDA to evaluateactual 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. GAAP39measure and should not be considered an alternative to net income (loss), net cash provided by operating activities or any other performance or liquiditymeasure determined in accordance with U.S. GAAP. In addition, our calculations of Adjusted EBITDA are not necessarily comparable to EBITDA or AdjustedEBITDA as calculated by other companies.Results of OperationsThe 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 anddivestitures, 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%) Average sales price Oil (per Bbl) Sales price $47.72 $39.52 $8.20 21%Effect of net settlements on matured derivative instruments(1) $(3.64) $8.40 $(12.04) (143%)Realized oil price after derivatives $44.08 $47.92 $(3.84) (8%)Natural gas (per Mcf) $2.88 $2.39 $0.49 21% Average unit costs per Boe Lease operating expenses $16.87 $15.35 $1.52 10%Oil and natural gas production taxes $2.59 $1.96 $0.63 32%Depreciation, depletion and amortization $13.83 $15.61 $(1.78) (11%)General and administrative expenses $4.46 $4.66 $(0.20) (4%)(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 deferredpremiums 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 onmatured 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 derivativecontracts in July 2016 or the related $2.8 million premiums paid at inception of the oil derivative contracts in January 2015.Year Ended December 31, 2017 Compared with Year Ended December 31, 2016Operating Revenues. The following table provides oil and natural gas sales data for the years ended December 31, 2017, and 2016: Year Ended December 31, (in thousands) 2017 2016 Change % Change Oil sales $57,689 $54,773 $2,916 5%Natural gas sales 1,240 1,325 (85) (6%)Total oil and natural gas sales $58,929 $56,098 $2,831 5%40The following table details the change in revenues due to price and volume variances: (in thousands, except prices) Change in prices ProductionVolumes Total Net DollarEffect ofChange Effects of changes in sales price Oil (Bbls) $8.20 1,209 $9,913 Natural gas (Mcf) $0.49 431 211 Total revenues due to change in price 10,124 Change inProductionVolumes Prior PeriodAverage Prices Total Net DollarEffect ofChange Effects of production volumes Oil (Bbls) (177) $39.52 $(6,998)Natural gas (Mcf) (123) $2.39 (295)Total revenues due to change in production volumes (7,293)Total change in revenues $2,831The change in oil and natural gas volumes was primarily due to the following: •divestiture of our Hugoton properties in 2016; •primary production declines at select properties in the Permian region; •increasing water cuts at select maturing waterflood properties in Southern Oklahoma, coupled with the sale of the Southern Oklahomaproperties on December 22, 2017; •production from the 2016 Permian Bolt-On acquisition and 2017 Wheatland acquisition properties; •successful new drill results at a Permian Bolt-On property; and •positive waterflood responses at key properties located in the Permian and Northeastern Oklahoma. Loss on derivatives, net. The table below summarizes the non-cash and cash components of our commodity derivative contracts as well as the change for theyears ended December 31, 2017, and 2016: Year Ended December 31, (in thousands) 2017 2016 Change % Change Cash settlements on matured derivatives(1) $(369) $20,511 $(20,880) (102%)Cash settlements on early terminations of derivatives(1) 582 5,820 (5,238) (90%)Non-cash change in fair value of derivatives (2,158) (38,533) 36,375 94%Total loss on derivatives, net $(1,945) $(12,202) $10,257 84%(1) The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.Production expenses. The following table summarizes the change in oil and natural gas production expense for the years ended December 31, 2017, and2016: Year Ended December 31, (in thousands) 2017 2016 Change % Change Lease operating expenses $21,614 $22,692 $(1,078) (5%)Oil and natural gas production taxes 3,321 2,893 428 15%Total oil and natural gas production expenses $24,935 $25,585 $(650) (3%)Effective production tax rate 5.7% 5.2% 0.5% 10%The change in lease operating expenses was primarily due to the following: •divestiture of our Hugoton properties in July 2016; •reduced spending in our Southern Oklahoma properties; •incremental costs associated with properties acquired in the Permian Bolt-On and Wheatland Acquisitions; •non-routine costs in Northeastern Oklahoma related to storm damage; and •discontinuation of the EOR tax credit at one of our Northeastern Oklahoma units effective July 1, 2017.41The following table summarizes production expenses per Boe data for the years ended December 31, 2017, and 2016: Year Ended December 31, (per Boe) 2017 2016 Change % Change Lease operating expenses $16.87 $15.35 $1.52 10%Oil and natural gas production taxes 2.59 1.96 0.63 32%Total oil and natural gas production expenses per Boe $19.46 $17.31 $2.15 12%The change in production expenses per Boe was primarily due to: •lower production volumes in 2017; and •discontinuation of the EOR tax credit at one of our Northeastern Oklahoma units effective July 1, 2017.Depreciation, Depletion, Amortization and Impairment Expenses. The following table provides our non-cash depreciation, depletion and amortization(“DD&A”) and impairment expense for the years ended December 31, 2017, and 2016: Year Ended December 31, (in thousands) 2017 2016 Change % Change Depreciation, depletion and amortization $17,713 $23,074 $(5,361) (23%)Impairment 24,746 895 23,851 2665%Impairment - assets held for sale 296 3,578 (3,282) (92%)Total DD&A and impairment $42,755 $27,547 $15,208 55%The change in DD&A was due to: •decrease in depletion rates due to increased reserves; •reduced asset carrying values due to impairment in 2017; •decrease in production volumes; and •the net impact of the Hugoton divestiture and the Permian Bolt-On and Wheatland acquisitions.Impairment of proved oil and natural gas properties was due to: •margin compression caused by lower future oil pricing and a higher cost profile on one of our Northeastern Oklahoma projects; •longer than anticipated response times to injection at one of our Permian projects; and •the 2016 non-cash impairment that resulted from a revision of reserve estimates for a property located in the Permian region.Impairment of proved oil and natural gas properties held for sale was due to: •the 2017 impairment related to the Nolan County divestiture properties, deemed to meet held-for-sale accounting criteria as of December31, 2017. •the 2016 impairment was related to the Hugoton divestiture that was deemed to meet held-for-sale accounting criteria as of June 30, 2016.General and Administrative Expenses. The following table provides components of our general and administrative (“G&A”) for the years ended December31, 2017, and 2016: Year Ended December 31, (in thousands, except for per Boe) 2017 2016 Change % Change General and administrative expenses $5,285 $5,706 $(421) (7%)Non-cash compensation 434 1,184 (750) (63%)Total general and administrative expenses $5,719 $6,890 $(1,171) (17%)General and administrative expenses (per Boe) $4.46 $4.66 (0.20) (4%)The decrease in G&A was primarily due to: •lower salaries expenses resulting from a reduced headcount in 2017; •the relocation and closure of our Dallas office in August 2016; and •fewer awards issued and lower unit price of stock-based compensation awards.42Loss on sales of oil and natural gas properties, net. Loss on sales of oil and natural gas properties, net, for the year ended December 31, 2017, included a $4.2million loss related to the Southern Oklahoma divestiture in December 2017, partially offset by a $0.2 million gain on sale of other properties. For the yearended December 31, 2016, loss on sales of oil and natural gas properties, net, included a $0.6 million loss primarily related to the Hugoton divestiture.Interest Expense. Interest expense is impacted by our borrowings outstanding, interest rates, commitment fees and related debt placement fees which areamortized over the life of the credit agreement. The following table sets forth interest expense for the years ended December 31, 2017, and 2016: Year Ended December 31, (in thousands) 2017 2016 Change % Change Interest expense $6,472 $7,487 $(1,015) (14%)Average effective interest rate 3.99% 3.92% 0.07% 2%The change in interest expense was primarily due to: •lower outstanding borrowings; offset by a •higher effective interest rate caused by an increase in the underlying market rate.Liquidity and Capital ResourcesOur ability to finance our operations, fund our capital expenditures and acquisitions, meet or refinance our debt obligations and meet our collateralrequirements will depend on our future cash flows. Our ability to generate cash is subject to a number of factors, some of which are beyond our control,including weather, oil and natural gas prices, operating costs and maintenance capital expenditures, as well as general economic, financial, competitive,legislative, regulatory and other factors. Historically, our primary use of cash has been for debt reduction, capital spending, including acquisitions, anddistributions.Since November 2014, oil prices have been extremely volatile, impacting the way we conduct business. In response, we have implemented a numberof adjustments to strengthen our financial position. We have continued to hedge a portion of our production to limit downside and volatility in theprevailing commodity price environment. At December 31, 2017, we had commodity derivative contracts covering a portion of our anticipated oilproduction through 2019. We have aggressively pursued cost reductions to improve profitability and maximize cash flows. Our primary cost reductioninitiatives encompass periodic economic review of each well within our portfolio along with ongoing scrutiny of LOE and G&A. We further reduced thePartnership’s weighted average cash operating break-even costs per Boe with the July 2016 divestiture of our higher cost Hugoton properties, the December2017 divestiture of Southern Oklahoma assets and the August 2016 acquisition of the Permian Bolt-On properties which carry a lower cost profile on arelative basis. Additionally in the third quarter 2015, we indefinitely suspended our quarterly cash distributions on common units. Our liquidity position at February 28, 2018, consisted of $1.0 million of available cash and $34.8 million of available borrowings under our revolvingcredit facility. Our borrowing base is redetermined in the spring and fall of each year.Revolving Credit FacilityDuring the quarter ended September 30, 2017, we were not in compliance with our leverage ratio calculation. On November 10, 2017, the Partnershipreceived a waiver from the Administrative Agent and the Lenders of our revolving credit facility waiving the noncompliance through December 15, 2017. OnDecember 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 NolanCounty divestiture on January 9, 2018, be applied to the borrowings outstanding.On January 31, 2018, Amendment 12 to the credit agreement was executed, extending the maturity of our credit facility from November 2018 untilNovember 2020, and increasing the borrowing base of the Partnership’s revolving credit facility to $125.0 million as of January 31, 2018. The lenders alsowaived 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 endedSeptember 30, 2017. The amendment also required the Partnership to have a minimum liquidity of 20% prior to making any distributions to the PreferredUnitholders. At February 28, 2018, the outstanding borrowings of our revolving credit facility were $90.2 million.Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able tofund our planned capital expenditures budget, meet our debt service requirements, and fund our other commitments and obligations. Although we currentlyexpect our sources of cash to be sufficient to meet our near-term liquidity needs, there can be no assurance that our liquidity requirements will continue to besatisfied due to the discretion of our lenders to decrease our borrowing base.43Due to the volatility of commodity prices, we may not be able to obtain funding in the equity or capital markets on terms we find acceptable. The cost ofobtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighterlending standards, and reduced and, in some cases, ceased to provide any new funding.Capital RequirementsOur business requires continual investment to upgrade or enhance existing operations in order to increase and maintain our production and the size ofour asset base. The primary purpose of growth capital is to acquire and develop producing assets that allow us to increase our production and asset base. Todate, we have funded acquisitions through a combination of cash, available borrowing capacity under our revolving credit facility and through the issuanceof equity, including convertible preferred units.Our current estimated capital spending for 2018 is $11.3 million for the development, growth and maintenance of our oil and natural gas properties.We will adjust our capital program in response to business conditions and operating results along with our evaluation of additional developmentopportunities that are identified throughout the year.Commodity Derivative ContractsOur 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 commodityderivative 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 oilproduction over a fixed period of time. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contractswhen we believe market conditions or other circumstances suggest that it is prudent to do so, or as required by our lenders. At December 31, 2017, we hadcommodity derivative contracts covering 67% and 15%, respectively, of our estimated 2018 and 2019 average daily production (estimate calculated basedon the mid-point of our 2018 Boe production guidance as released on February 28, 2018 and multiplied by a 95% oil weighting based on fourth quarter 2017reported production volumes). See Note 5 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” foradditional information.Preferred UnitsAs of December 31, 2017, we had issued $25.0 million of Class A Preferred Units, which were issued during August 2016 through a private placement.Class A Preferred unitholders receive a cumulative, quarterly distribution on all Class A Preferred Units then outstanding at an annual rate of 8.0%, or in theevent that the Partnership’s existing secured indebtedness prevents the payment of a cash distribution to all holders of the Class A Preferred Units, in kind(additional Class A Preferred Units), at an annual rate of 10.0%. Such distributions will be paid for each quarter within 45 days after such quarter end, or asotherwise permitted to accumulate pursuant to the Partnership Agreement. See Note 10 to the Consolidated Financial Statements included in Item 8.“Financial Statements and Supplementary Data” for additional information.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. ThePartnership will pay holders of the Class B Preferred Units a cumulative, quarterly distribution in cash at an annual rate of 8.0%, or under certaincircumstances, in additional Class B Preferred Units, at an annual rate of 10.0%. See Note 15 to the Consolidated Financial Statements included in Item 8.“Financial Statements and Supplementary Data” for additional information.Sources and Uses of CashThe following table summarizes our net increase (decrease) in cash for the years ended December 31, 2017, and 2016: Year Ended December 31, (in thousands) 2017 2016 Change % Change Net cash provided by operating activities $17,246 $43,936 $(26,690) (61%)Net cash provided by (used in) investing activities $6,997 $(8,475) $15,472 183%Net cash used in financing activities $(24,770) $(33,717) $8,947 27%Net (decrease) increase in cash and cash equivalents $(527) $1,744 $(2,271) (130%)Operating Activities. The decrease in operating cash flows during the year ended December 31, 2017, was primarily attributable to lower cash settlementsreceived from matured derivatives.44Investing Activities. During the year ended December 31, 2017, our cash flow investing activities included: •proceeds of $22.1 million primarily from the sale of oil and natural gas properties in Southern Oklahoma; •the acquisition of oil and natural gas properties for $5.0 million primarily in Oklahoma; and •drilling and completion activities of $9.9 million.During the year ended December 31, 2016, our cash flow investing activities included: •the acquisition of oil and natural gas properties for $18.7 million primarily in Texas; •drilling and completion activities of $7.2 million; partially offset by •proceeds of $17.6 million from the sale of oil and natural gas properties in the Hugoton area.Financing Activities. During the year ended December 31, 2017, we had the following financing cash flow activities: •proceeds of $6.0 million from the revolving credit facility; •payments of $29.0 million on the revolving credit facility; and •distributions of $1.5 million to preferred unitholders.During the year ended December 31, 2016, we had the following financing cash flow activities: •payments of $58.0 million on the revolving credit facility; •net proceeds of $24.6 million received from the sale of Class A Preferred Units; and •distributions of $0.3 million to Class A preferred unitholders.Critical Accounting Policies and EstimatesAccounting policies we consider significant are summarized in Note 2 to the Consolidated Financial Statements included in Item 8. “FinancialStatements and Supplementary Data” of this report. Certain accounting policies require management to make critical accounting estimates. Accountingestimates are considered critical if the nature of the estimates and assumptions involves a high degree of subjectivity and judgment concerning uncertainmatters and the impact of the estimates and assumptions is material to our financial position or results of operations. Additional information regarding ourcritical estimates is provided below.Derivative Contracts and Hedging ActivitiesCurrent accounting rules require that all derivative contracts, other than those that meet specific exclusions, be recorded at fair value. Quoted marketprices are the best evidence of fair value. If quotations are not available, management’s best estimate of fair value is based on the quoted market price ofderivatives with similar characteristics or on other valuation techniques. We use certain pricing models to determine the fair value of our derivative contracts.Inputs to the pricing models include publicly available prices from a compilation of data gathered from third parties and brokers. We compare our estimatesof the fair values of our derivative contracts with those provided by our counterparties. There have been no significant differences. For additional informationregarding derivatives, see Note 5 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data.”Revenue recognitionWe follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on our share of actualproceeds from oil and natural gas sold to purchasers. Natural gas revenues would not have been significantly altered for the period presented had theentitlements method of recognizing natural gas revenues been utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability isrecorded. We had no significant natural gas imbalances at December 31, 2017, and 2016. We do not extract NGLs from our natural gas production prior to thesale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extract NGLs from the natural gas stream sold by us to them,we have no ownership in such NGLs. Therefore we do not report NGLs in our production or proved reserves.Successful Efforts Method of AccountingAccounting for oil and natural gas properties under the successful efforts method of accounting requires management to make estimates that may havea material impact on our financial position as they determine the carrying amount of our oil and natural gas properties and the amount of depletion andimpairment expense. We believe the following to be critical accounting estimates associated with the successful efforts method of accounting of our oil andnatural gas properties:Oil and Natural Gas ReservesOur estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analysis demonstrate, withreasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic45parameters. The estimates of our proved reserves as of December 31, 2017, are based on reserve reports prepared by our reservoir engineering staff and auditedby CG&A. The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations aboutthe recoverability of reserves in future years.The accuracy of our reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data,the accuracy of various economic assumptions and the judgments of the individuals preparing the estimates. In addition, our proved reserve estimates are alsoa function of many assumptions, all of which could deviate significantly from actual results. For example, when the price of oil and natural gas increases, theeconomic lives of our properties are extended, thus increasing estimated proved reserve quantities and making certain projects economically viable.Likewise, if oil and natural gas prices decrease, the economic lives of our properties are reduced and certain projects may become uneconomic, reducingestimated proved reserve quantities. Oil and natural gas price volatility adds to the uncertainty of our reserve quantity estimates. As such, reserve estimatesmay materially vary from the ultimate quantities of oil and natural gas eventually recovered. For additional information regarding estimates of reserves,including the standardized measure of discounted future net cash flows, see “Supplementary Information” in Item 8. “Financial Statements andSupplementary Data” and see also Item 1. “Business.”Impairment of Oil and Natural Gas PropertiesWe review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts methodof accounting, whenever events or circumstances indicate that the carrying value exceeds management’s estimate of fair value. The carrying values of provedproperties are reduced to fair value when the expected undiscounted future cash flow is less than net book value. The fair values of proved properties aremeasured using valuation techniques consistent with the income approach, converting future cash flow to a single discounted amount. Significant inputsused to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and developmental costs; (iii) future commodityprices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in our estimated cash flows are the productof a process that begins with NYMEX-WTI forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors thatmanagement believes will impact realizable prices. We review our oil and natural gas properties by amortization base (field) or by individual well for thosewells not constituting part of an amortization base.Asset Retirement ObligationsWe have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gasproduction operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or drillinga well. Determining the future restoration and removal requires management to make estimates and judgments, including the ultimate settlement amounts,inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Weestimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk adjusted discount rate and an inflationfactor in order to determine the current present value of this obligation. We are required to record the fair value of a liability for the ARO in the period inwhich it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of futureARO on an annual basis, or more frequently, if an event or circumstances occur that would impact our assumptions. To the extent future revisions to theseassumptions impact the present value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oiland natural gas property asset balance. Over time, the liability is accreted each period toward its future value and the capitalized cost is depleted as acomponent of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.See Note 7 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for additional information.AcquisitionsThe estimated fair values of proved oil and natural gas properties acquired in business combinations are based on a discounted cash flow model andmarket assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount offuture development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates. Based on theunobservable nature of certain of the inputs, the estimated fair value of the oil and natural gas properties acquired is deemed to use Level 3 inputs. See Note 6to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for additional information.Off–Balance Sheet ArrangementsAt December 31, 2017, we had no off–balance sheet arrangements.46Recently Issued Accounting PronouncementsSee Note 2 to the Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for additional informationregarding recently issued accounting pronouncements.ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKAs a smaller reporting company, we are not required to provide the information otherwise required by this item. 47ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and PartnersMid-Con Energy Partners, LPOpinion on the financial statementsWe have audited the accompanying consolidated balance sheets of Mid-Con Energy Partners, LP (a Delaware limited partnership) and subsidiaries (the“Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, cash flows, and changes in equity for each of the twoyears in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financialstatements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operationsand its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in theUnited States of America. Basis for opinionThese financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financialstatements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulationsof the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, norwere we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding ofinternal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control overfinancial reporting. Accordingly, we express no such opinion.Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, andperforming procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well asevaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion./s/ GRANT THORNTON LLPWe have served as the Partnership’s auditor since 2005. Tulsa, OklahomaFebruary 28, 2018 48Mid-Con Energy Partners, LP and subsidiariesConsolidated Balance Sheets(in thousands, except number of units) December 31, 2017 2016 ASSETS Current assets Cash and cash equivalents $1,832 $2,359 Accounts receivable Oil and natural gas sales 5,262 5,302 Other 103 233 Prepaid expenses and other 166 512 Assets held for sale, net 2,058 — Total current assets 9,421 8,406 Property and equipment Oil and natural gas properties, successful efforts method Proved properties 335,796 441,479 Unproved properties 369 — Other property and equipment 427 289 Accumulated depletion, depreciation, amortization and impairment (129,101) (176,551)Total property and equipment, net 207,491 265,217 Other assets 2,451 2,663 Total assets $219,363 $276,286 LIABILITIES, CONVERTIBLE PREFERRED UNITS AND EQUITY Current liabilities Accounts payable Trade $593 $256 Related parties 1,631 3,431 Derivative financial instruments 4,252 5,314 Accrued liabilities 603 146 Liabilities related to assets held for sale 77 — Total current liabilities 7,156 9,147 Derivative financial instruments 666 2,495 Long-term debt 99,000 122,000 Other long-term liabilities 70 93 Asset retirement obligations 10,249 11,331 Commitments and contingencies Class A convertible preferred units - 11,627,906 issued and outstanding, respectively 20,534 19,570 Equity, per accompanying statements General partner (572) (248)Limited partners- 30,090,463 and 29,912,230 units issued and outstanding, respectively 82,260 111,898 Total equity 81,688 111,650 Total liabilities, convertible preferred units and equity $219,363 $276,286 See accompanying notes to consolidated financial statements 49Mid-Con Energy Partners, LP and subsidiariesConsolidated Statements of Operations(in thousands, except per unit data) Year Ended December 31, 2017 2016 Revenues Oil sales $57,689 $54,773 Natural gas sales 1,240 1,325 Loss on derivatives, net (1,945) (12,202)Total revenues 56,984 43,896 Operating costs and expenses Lease operating expenses 21,614 22,692 Oil and natural gas production taxes 3,321 2,893 Impairment of proved oil and natural gas properties 24,746 895 Impairment of proved oil and natural gas properties held for sale 296 3,578 Depreciation, depletion and amortization 17,713 23,074 Accretion of discount on asset retirement obligations 520 577 General and administrative 5,719 6,890 Total operating costs and expenses 73,929 60,599 Loss on sales of oil and natural gas properties, net (3,950) (560)Loss from operations (20,895) (17,263)Other (expense) income Interest income 11 12 Interest expense (6,472) (7,487)Other income (expense) 60 (76)Loss on settlements of asset retirement obligations (37) — Total other expense (6,438) (7,551)Net loss (27,333) (24,814)Less: Distributions to preferred unitholders 3,063 1,249 Less: General partner's interest in net loss (324) (295)Limited partners’ interest in net loss $(30,072) $(25,768) Limited partners’ interest in net loss per unit Basic and diluted $(0.99) $(0.86)Weighted average limited partner units outstanding Limited partner units (basic and diluted) 30,002 29,834 See accompanying notes to consolidated financial statements 50Mid-Con Energy Partners, LP and subsidiariesConsolidated Statements of Cash Flows(in thousands) Year Ended December 31, 2017 2016 Cash Flows from Operating Activities Net loss $(27,333) $(24,814)Adjustments to reconcile net loss to net cash provided by operating activities Depreciation, depletion and amortization 17,713 23,074 Debt issuance costs amortization 1,384 1,372 Accretion of discount on asset retirement obligations 520 577 Impairment of proved oil and natural gas properties 24,746 895 Impairment of proved oil and natural gas properties held for sale 296 3,578 Loss on settlements of asset retirement obligations 37 — Cash paid for settlements of asset retirement obligations (95) — Mark to market on derivatives Loss on derivatives, net 1,945 12,202 Cash settlements (paid) received for matured derivatives (369) 20,511 Cash settlements received for early terminations and modifications of derivatives, net 582 5,820 Cash premiums paid for derivatives, net (5,048) (5,161)Loss on sales of oil and natural gas properties, net 3,950 560 Non-cash equity-based compensation 434 1,184 Changes in operating assets and liabilities Accounts receivable 40 (751)Other receivables 150 4,935 Prepaid expenses and other (655) (39)Accounts payable - trade and accrued liabilities 427 69 Accounts payable - related parties (1,478) (76)Net cash provided by operating activities 17,246 43,936 Cash Flows from Investing Activities Acquisitions of oil and natural gas properties (5,034) (18,722)Additions to oil and natural gas properties (9,947) (7,223)Additions to other property and equipment (137) (165)Proceeds from sales of oil and natural gas properties 22,115 17,635 Net cash provided by (used in) investing activities 6,997 (8,475)Cash Flows from Financing Activities Proceeds from line of credit 6,000 — Payments on line of credit (29,000) (58,000)Offering costs (99) (16)Debt issuance costs (171) (68)Proceeds from sale of Class A convertible preferred units, net of offering costs — 24,646 Distributions to Class A convertible preferred units (1,500) (279)Net cash used in financing activities (24,770) (33,717)Net (decrease) increase in cash and cash equivalents (527) 1,744 Beginning cash and cash equivalents 2,359 615 Ending cash and cash equivalents $1,832 $2,359 See accompanying notes to consolidated financial statements 51Mid-Con Energy Partners, LP and subsidiariesConsolidated Statements of Changes in Equity(in thousands) General Limited Partner Total Partner Units Amount Equity Balance, December 31, 2015 $47 29,725 $130,451 $130,498 Equity-based compensation — 187 1,184 1,184 Offering costs — — (16) (16)Distributions to Class A convertible preferred units — — (779) (779)Allocation of value to beneficial conversion feature of Class A convertible preferredunits — — 6,047 6,047 Accretion of beneficial conversion feature of Class A convertible preferred units — — (470) (470)Net loss (295) (24,519) (24,814)Balance, December 31, 2016 (248) 29,912 111,898 111,650 Equity-based compensation — 179 434 434 Distributions to Class A convertible preferred units — — (2,000) (2,000)Accretion of beneficial conversion feature of Class A convertible preferred units — — (1,063) (1,063)Net loss (324) — (27,009) (27,333)Balance, December 31, 2017 $(572) 30,091 $82,260 $81,688 See accompanying notes to consolidated financial statements 52Mid-Con Energy Partners, LP and subsidiariesNotes to Consolidated Financial StatementsNote 1. Organization and Nature of OperationsNature of OperationsMid-Con Energy Partners is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition anddevelopment of producing oil and natural gas properties in North America, with a focus on EOR. Our limited partner units (“common units”) are listed underthe symbol “MCEP” on the NASDAQ. Our general partner is Mid-Con Energy GP, a Delaware limited liability company.ReclassificationsCertain amounts in the consolidated balance sheets for the prior year have been reclassified to conform to the 2017 presentation. The line itemsimpacted were prepaid expenses and other assets, accounts payable - trade and accounts payable - related parties. These reclassifications have no impact onpreviously reported total assets, total liabilities, net income (loss) or total operating cash flows.Non-cash Investing, Financing and Supplemental Cash Flow InformationThe following presents the non-cash investing, financing and supplemental cash flow information for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Non-cash investing and financing information Change in oil and natural gas properties - accrued capital expenditures $(310) $(259)Tenant improvement allowance deferred - other property and equipment $— $124 Supplemental cash flow information Cash paid for interest $5,041 $6,198 Note 2. Summary of Significant Accounting PoliciesBasis of presentation and principles of consolidationThe accompanying financial statements and related notes present our consolidated financial position as of December 31, 2017, and 2016, and theresults of operations, cash flows and changes in equity for the years then ended December 31, 2017, and 2016. The accompanying consolidated financialstatements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Our subsidiary isMid-Con Energy Properties. All intercompany transactions and account balances have been eliminated. We aggregate all of our oil and natural gas propertiesinto one business segment engaged in the development and production of oil and natural gas properties.Use of estimatesThe preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reportedamounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenuesand expenses during the reporting periods. Actual results could differ from those estimates. Depletion and impairment of oil and natural gas properties, inpart, are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of provedreserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved oiland natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity priceoutlooks. Other significant estimates include, but are not limited to, ARO, fair value of assets acquired and liabilities assumed in business combinations andfair value of derivative financial instruments.Cash and cash equivalentsWe consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to becash equivalents.53Accounts receivableAccounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customersand bad debts are recorded based on an account level review after all means of collection have been exhausted, and the potential recovery is consideredremote. At December 31, 2017, and 2016, we did not have any reserves for doubtful accounts and we did not incur any expenses related to bad debts in anyperiod presented.Revenue recognitionWe follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on our share of actualproceeds from oil and natural gas sold to purchasers. Natural gas revenues would not have been significantly altered for the period presented had theentitlements method of recognizing natural gas revenues been utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability isrecorded. We had no significant natural gas imbalances at December 31, 2017, and 2016. We do not extract NGLs from our natural gas production prior to thesale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extract NGLs from the natural gas stream sold by us to them,we have no ownership in such NGLs. Therefore we do not report NGLs in our production or proved reserves.Oil and natural gas propertiesOur oil and natural gas development and production activities are accounted for using the successful efforts method. Under this method all costsassociated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalizedcosts relating to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation ofcapitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis. Capitalized costs ofindividual properties abandoned or retired are charged to accumulated depletion, depreciation and amortization. Proceeds from sales of individual propertiesare credited to property costs. No gain or loss is recognized until the entire amortization base (field) is sold or abandoned.Costs associated with unproved properties are excluded from depletion until proved reserves are established or impairment determined. When provenreserves are established any unproved property costs associated with the project are transferred to proved properties and included in depletion. Unprovedproperties are assessed at least annually to ascertain whether impairment has occurred. In addition, impairment assessments are made for interim reportingperiods if facts and circumstances exist that suggest impairment may have occurred. The impairment test for unproved properties is not based on theestimated fair value of the unproved properties. The impairment assessment includes consideration of our intent to fully develop our unproved properties,remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of provedreserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others.Costs of significant proved non-producing properties and wells in the process of being drilled are excluded from depletion until such time as theproved reserves are established or impairment is determined. Costs of significant development projects are excluded from depletion until the related project iscompleted. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intendeduse. We had no capitalized interest during any of the periods presented. We review our long-lived assets to be held and used, including proved oil andnatural gas properties whenever events or circumstances indicate that the carrying value may be greater than management’s estimates of its future net cashflows, including cash flows from proved reserves. The need to test an asset for impairment may result from significant declines in sales prices or downwardrevisions in estimate quantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted futurenet cash flows, an impairment expense is recognized for the difference between the estimated fair value and the carrying value of the assets. We review our oiland natural gas properties by amortization base (field) or by individual well for those wells not constituting part of an amortization base. These evaluationsinvolve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future coststo produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates andother factors. Cash flow estimates for the impairment testing excludes derivative instruments used to mitigate the price risk related to lower future oil andnatural gas prices.We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gasproduction operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or drillinga well. Determining the future restoration and removal requires management to make estimates and judgments, including the ultimate settlement amounts,inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Weestimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk adjusted discount rate and an inflationfactor in order to determine the current present value of this obligation. We are required to record the fair value of a liability for the ARO in the period inwhich it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of futureARO on an annual basis, or more frequently, if an event or circumstances occur that would impact our assumptions. To the extent future revisions to theseassumptions impact the present value of the abandonment liability, management will make corresponding adjustments54to both the ARO and the related oil and natural gas property asset balance. Over time, the liability is accreted each period toward its future value and thecapitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costsdiffer from the recorded liability. See Note 7 for additional information.Derivatives and hedgingOur risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly,we utilize commodity derivatives (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodityderivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggestthat it is prudent to do so, or as required by our lenders. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. The Partnership netsthe fair value of derivatives by counterparty where the right of offset exists and determines the fair value of its derivatives by utilizing certain pricing modelsto validate the data provided by third parties. See Note 6 Fair Value Disclosures for more information.We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value ofunsettled derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedgingactivities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-marketadjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to theirexpiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the relatedcontracts mature. Gains and losses on derivatives are included in cash flows from operating activities. See Note 5 for discussion regarding DerivativeFinancial Instruments.Equity-based compensationThe cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value and is recorded ascompensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that theperformance criteria will be met. On January 1, 2017, we adopted ASU 2016-09 Compensation – Stock Compensation (Topic 718): Improvements toEmployee Share-Based Payment Accounting (“ASU 2016-09”); therefore, we recognize forfeitures of equity awards as they occur. No compensation expenseis recognized for equity instruments that do not vest.Debt issuance costsDebt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense inthe consolidated statements of operations over the remaining life of the agreement. Since our debt consists of a revolving credit facility, net debt placementcosts are presented in “Other Assets” in our consolidated balance sheets. When debt is retired before its scheduled maturity date, any remaining issuance costsassociated with that debt are expensed.Income taxesThe partnership is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, taxable income orloss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from thosereported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets andliabilities.Allocation of Net Income or LossNet income or loss is allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss isallocated to the limited partner unitholders net of Preferred Unit distributions, including accretion of the Preferred Unit beneficial conversion feature. In theevent of net income, diluted net income per partner unit reflects the potential dilution of non-vested restricted stock awards and the conversion of PreferredUnits to common units.Recently Issued Accounting StandardsIn May 2014, the Financial Accounting Standards Board (“FASB”) issued a comprehensive new revenue recognition standard that supersedes therevenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil andGas-Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods orservices to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods orservices. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity’s nature,amount, timing and uncertainty of55revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment whenconsidering the terms of a contract and all relevant facts and circumstances. The standard allows for two transition methods: (a) a full retrospective adoptionin which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the mostcurrent period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statementline items. Several times during 2016, the FASB issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the followingpotential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) toclarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessingcollectability, presentation of sales taxes, non-cash consideration and completed contract modifications at transition. This standard is effective for annualreporting periods beginning after December 15, 2017, including interim periods within that reporting period. We adopted this standard effective January 1,2018, using the modified retrospective approach. The cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, didnot result in an adjustment to opening retained earnings. We have concluded that our revenue recognition under the new guidance will not materially differfrom our current revenue recognition practice. We have added controls around our contract process to determine if changes to our revenue recognitionpractices are warranted. We will continue to disclose revenue in the financial statements at a level consistent with our current breakout of sales revenue byproduct type. In 2018, we will present expanded qualitative disclosures related to our oil and natural gas sales contracts.In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requiresall leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance andoperating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periodsbeginning after December 15, 2018, and early adoption is permitted. We plan to adopt this standard on January 1, 2019 and believe the primary impact ofadoption will be the recognition of assets and liabilities on our balance sheet for current operating leases. We are still evaluating the impact of this standard.In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805),” with the objective of adding guidance to assist inevaluating whether transactions should be accounted for as asset acquisitions or as business combinations. The amendments in this update provide a screento determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquiredassets is concentrated in a single asset or a group of similar assets, the set is not a business. This screen reduces the number of transactions that need to befurther evaluated. If the screen is not met, to be considered a business, the set of assets and activities must include an input and a substantive process thattogether significantly contribute to the ability to create output and remove the evaluation of whether a market participant could replace missing elements.We adopted this standard January 1, 2018. We do not anticipate a material impact to our consolidated financial statements upon adoption of this standard.Note 3. Acquisitions, Divestitures and Assets Held for SaleAcquisitionsAcquisitions are accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in acquisitions are recorded inour consolidated balance sheets at their estimated fair values as of the acquisition date using assumptions that represent Level 3 fair value measurementinputs. See Note 5 in this section for additional discussion of our fair value measurements. Results of operations attributable to the acquisition subsequent tothe closing are included in our consolidated statements of operations.WheatlandIn June 2017, we acquired multiple oil and natural gas properties located in Oklahoma County and Cleveland County, Oklahoma for cashconsideration of $4.1 million, after preliminary post-closing purchase price adjustments.The recognized fair values of the assets acquired and liabilities assumed are as follows: (in thousands) Fair value of net assets acquired Proved oil and natural gas properties $4,399 Other property and equipment 132 Total assets acquired 4,531 Fair value of net liabilities assumed Asset retirement obligation 407 Net assets acquired $4,12456The following table presents revenues and expenses of the oil and natural gas properties acquired included in the accompanying consolidatedstatements of operations for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Oil and natural gas sales $1,373 $— Expenses(1) $1,009 $—(1) Expenses include LOE, production taxes, accretion and depletion.Permian Bolt-OnIn August 2016, we acquired multiple oil and natural gas properties located in Nolan County, Texas (the “Permian Bolt-On”) for cash consideration of$18.7 million, after post-closing purchase price adjustments. The transaction was funded by a private offering of $25.0 million Class A Convertible PreferredUnits (“Class A Preferred Units”). See Note 10 in this section for additional information regarding the issuance of the Class A Preferred Units.The recognized fair values of the assets acquired and liabilities assumed are as follows: (in thousands) Fair value of net assets acquired Proved oil and natural gas properties $19,323 Total assets acquired 19,323 Fair value of net liabilities assumed Asset retirement obligation 622 Net assets acquired $18,701The following table presents revenues and expenses of the oil and natural gas properties acquired included in the accompanying consolidatedstatements of operations for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Oil and natural gas sales $8,511 $2,673 Expenses(1) $5,717 $1,640(1) Expenses include LOE, production taxes, accretion, depletion and impairment expenses.DivestituresEffective at closing, the operations and cash flows of the divested properties were eliminated from the ongoing operations of the Partnership and thePartnership has no continuing involvement in these properties. The divestitures did not represent a strategic shift and did not have a major effect on thePartnership’s operations or financial results.Southern OklahomaIn December 2017, we sold the properties located in the Southern Oklahoma for cash proceeds of $22.0 million, prior to post-closing purchase priceadjustments, and recognized a loss of $4.2 million.The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statementsof operations for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Oil and natural gas sales $9,252 $10,273 Expenses(1) $7,419 $8,897(1) Expenses include LOE, production taxes, accretion and depletion.HugotonIn July 2016, we sold the properties located in the Hugoton region for cash proceeds of $17.6 million, after post-closing purchase price adjustmentsand recognized a loss of $0.6 million. Additionally, we recorded impairment of proved oil and natural gas properties of $3.6 million when these propertieswere originally reported as held for sale.57The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statementsof operations for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Oil and natural gas sales $— $3,602 Expenses(1) $— $7,717(1) Expenses include LOE, production taxes, accretion, depletion and impairment expenses.Assets Held for SaleCertain oil and natural gas proved properties in Nolan County, Texas, were deemed to meet held-for-sale accounting criteria as of December 31, 2017.As a result, impairment of $0.3 million was recorded to reduce the carrying value of these assets to their estimated fair value of $1.5 million at December 31,2017. The net asset value of $1.6 million was presented in “Assets held for sale, net” and a net liability of $0.1 million was presented as “Liabilities related toassets held for sale” on our consolidated balance sheet. In January 2018, we completed the sale of these assets for $1.6 million, subject to customary post-closing sales price adjustments.In addition to the Nolan County properties, land in Southern Oklahoma met held-for-sale criteria as of December 31, 2017. The carrying value of $0.4million was presented in “Assets held for sale, net” on our consolidated balance sheet.Note 4. Equity AwardsWe have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and directors of our general partnerand its affiliates, including Mid-Con Energy Operating and ME3 Oilfield Service, who perform services for us. The Long-Term Incentive Program allows forthe award of unit options, unit appreciation rights, unrestricted units, restricted units, phantom units, distribution equivalent rights granted with phantomunits and other types of awards. The Long-Term Incentive Program is administered by Charles R. Olmstead, Executive Chairman of the Board, and Jeffrey R.Olmstead, President and Chief Executive Officer, and awards are approved by the Board. If an employee terminates employment prior to the restriction lapsedate, the awarded units are forfeited and canceled and are no longer considered issued and outstanding.On January 1, 2017, we adopted ASU 2016-09 and elected to recognize forfeitures of equity awards as they occur. The cumulative effect of adoptingASU 2016-09 was determined to be immaterial and no adjustment to retained earnings was made.The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2017: Number ofCommonUnits Approved and authorized awards 3,514,000 Unrestricted units granted (1,212,706)Restricted units granted, net of forfeitures (399,424)Equity-settled phantom units granted, net of forfeitures (441,169)Awards available for future grant 1,460,701We recognized $0.4 million and $1.2 million of total equity-based compensation expense for the years ended December 31, 2017, and 2016,respectively. These costs are reported as a component of G&A in our consolidated statements of operations.Unrestricted Unit AwardsDuring the year ended December 31, 2017, we granted 25,400 unrestricted units with an average grant date fair value of $2.65 per unit. During theyear ended December 31, 2016, we granted 73,932 unrestricted units with an average grant date fair value of $1.20 per unit.Restricted Unit AwardsRestricted units vest over two or three years. We did not issue any restricted units during the years ended December 31, 2017, and 2016.58A summary of our restricted unit awards for the years ended December 31, 2017, and 2016, is presented below: Number ofRestrictedUnits Average GrantDate Fair Valueper Unit Outstanding at December 31, 2015 222,833 $8.49 Units granted — — Units vested (112,478) 9.16 Units forfeited (33,433) 9.69 Outstanding at December 31, 2016 76,922 5.67 Units granted — — Units vested (69,560) 6.39 Units forfeited (1,000) 5.42 Outstanding at December 31, 2017 6,362 $5.42Equity-Settled Phantom Unit AwardsEquity-settled phantom units vest over two or three years and do not have any rights or privileges of a common unitholder, including the right todistributions, until vesting and the resulting conversion into common units. During the year ended December 31, 2017, we granted 27,000 equity-settledphantom units with a two-year vesting period and 14,500 equity-settled phantom units with a three-year vesting period. During the year ended December 31,2016, we granted 347,500 equity-settled phantom awards with one-third vesting immediately and the other two-thirds vesting over two years and 27,000equity-settled phantom awards with a three-year vesting period. As of December 31, 2017, there were $0.1 million of unrecognized compensation costsrelated to equity-settled phantom units. These costs are expected to be recognized over a weighted average period of ten months.A summary of our equity-settled phantom unit awards for the years ended December 31, 2017, and 2016, is presented below: Number of Equity-Settled PhantomUnits Average GrantDate Fair Valueper Unit Outstanding at December 31, 2015 77,500 $2.81 Units granted 374,500 1.55 Units vested (146,841) 2.03 Units forfeited (17,500) 2.02 Outstanding at December 31, 2016 287,659 1.64 Units granted 41,500 1.60 Units vested (153,833) 1.70 Units forfeited (57,831) 1.96 Outstanding at December 31, 2017 117,495 $1.45 Note 5. Derivative Financial InstrumentsOur 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. We enter into commodityderivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggestthat it is prudent to do so, or as required by our lenders. We account for our commodity derivative contracts at fair value. See Note 6 in this section for adescription of our fair value measurements.We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value ofour commodity derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedgingactivities consists of non-cash gains or losses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-marketadjustments, gains or losses arise from net amounts paid or received on monthly settlements, proceeds from or payments for termination of contracts prior totheir expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the relatedcontracts mature. Gains and losses on derivatives are included in cash flows from operating activities. Pursuant to the accounting standard that permitsnetting of assets and liabilities where the right of offset exists, we present the fair value of commodity derivative contracts on a net basis.59At December 31, 2017, and 2016, our commodity derivative contracts were in a net liability position with a fair value of $4.9 million and $7.8million, respectively. All of our commodity derivative contracts are with major financial institutions that are also lenders under our revolving credit facility.Should one of these financial counterparties not perform, we may not realize the benefit of some of our commodity derivative contracts under lowercommodity prices and we could incur a loss. During the two years ended December 31, 2017, and 2016, all of our counterparties have performed pursuant totheir commodity derivative contracts.The following tables summarize the gross fair value by the appropriate balance sheet classification, even when the derivative financial instruments aresubject to netting arrangements and qualify for net presentation in our consolidated balance sheets at December 31, 2017, and 2016: (in thousands) GrossAmountsRecognized Gross AmountsOffset in theConsolidatedBalance Sheet Net AmountsPresented in theConsolidatedBalance Sheet December 31, 2017 Assets Derivative financial instruments - current asset $39 $(39) $— Total 39 (39) — Liabilities Derivative financial instruments - current liability (3,890) (362) (4,252)Derivative deferred premium - current liability (401) 401 — Derivative financial instruments - long-term liability (666) — (666)Total (4,957) 39 (4,918)Net Liability $(4,918) $— $(4,918) (in thousands) GrossAmountsRecognized Gross AmountsOffset in theConsolidatedBalance Sheet Net AmountsPresented in theConsolidatedBalance Sheet December 31, 2016 Assets Derivative financial instruments - current asset $1,570 $(1,570) $— Derivative financial instruments - long-term asset 406 (406) — Total 1,976 (1,976) — Liabilities Derivative financial instruments - current liability (1,836) (3,478) (5,314)Derivative deferred premium - current liability (5,048) 5,048 — Derivative financial instruments - long-term liability (2,500) 5 (2,495)Derivative deferred premium - long-term liability (401) 401 — Total (9,785) 1,976 (7,809)Net Liability $(7,809) $— $(7,809)The following table presents the impact of derivative financial instruments and their location within the consolidated statements of operations: Year Ended December 31, (in thousands) 2017 2016 Net settlements on matured derivatives(1) $(369) $20,511 Net settlements on early terminations of derivatives(1) 582 5,820 Net change in fair value of derivatives (2,158) (38,533)Total loss on derivatives, net $(1,945) $(12,202)(1) The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.60At December 31, 2017, and 2016, our commodity derivative contracts had maturities at various dates through December 2019 and were comprised ofcommodity price swap, put and collar contracts. At December 31, 2017, we had the following oil derivatives net positions: Period Covered WeightedAverageFixed Price WeightedAverageFloor Price WeightedAverageCeiling Price Total BblsHedged/day NYMEX IndexSwaps - 2018 $51.33 $— $— 444 WTICollars - 2018 $— $44.38 $55.52 1,315 WTIPuts - 2018 $— $45.00 $— 164 WTISwaps - 2019 $51.48 $— $— 427 WTIAt December 31, 2016, we had the following oil derivatives net positions: Period Covered WeightedAverageFloor Price WeightedAverageCeiling Price Total BblsHedged/day NYMEXIndexCollars - 2017 $43.75 $50.68 658 WTIPuts - 2017 $50.00 $— 1,932 WTICollars - 2018 $44.38 $55.52 1,315 WTIPuts - 2018 $45.00 $— 164 WTICollars - 2019 $50.00 $60.52 427 WTI Note 6. Fair Value DisclosuresFair Value of Financial InstrumentsThe carrying amounts reported in our consolidated balance sheets for cash, accounts receivable and accounts payable approximate their fair values.The carrying amount of debt under our revolving credit facility approximates fair value because the revolving credit facility’s variable interest rate resetsfrequently and approximates current market rates available to us. We account for our commodity derivative contracts at fair value as discussed in “Assets andLiabilities Measures at Fair Value on a Recurring Basis” below.Fair Value MeasurementsFair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between marketparticipants at the measurement date. GAAP establishes a three-tier fair value hierarchy that is intended to increase consistency and comparability in fairvalue measurements and related disclosures. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities(Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded in the balance sheet are categorized based on the inputs tothe valuation technique as follows:Level 1 - Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active marketthat management has the ability to access. We consider active markets to be those in which transactions for the assets or liabilities occur in sufficientfrequency and volume to provide pricing information on an on-going basis.Level 2 - Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observableeither directly or indirectly for substantially the full term of the asset or liability. Level 2 instruments primarily include swap, call, put and collar contracts.Level 3 - Financial assets and liabilities for which values are based on prices or valuation approaches that require inputs that are both unobservableand significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant woulduse in pricing the asset or liability.When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair valuemeasurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. Changes in the observability ofvaluation inputs may result in a reclassification for certain financial assets or liabilities. We had no transfers in or out of Levels 1, 2 or 3 during the yearsended December 31, 2017, and 2016.61Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty andcannot be determined with precision. There were no changes in valuation approach or related inputs for the years ended December 31, 2017, and 2016.Assets and Liabilities Measured at Fair Value on a Recurring BasisWe account for commodity derivative contracts and their corresponding deferred premiums at fair value on a recurring basis utilizing certain pricingmodels. Inputs to the pricing models include publicly available prices from a compilation of data gathered from third parties and brokers. We validate thedata provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data incertain situations and confirming that those securities trade in active markets. The Partnership’s deferred premiums associated with its commodity derivativecontracts are categorized as Level 3, as the Partnership utilizes a net present value calculation to determine the valuation. See Note 5 in this section for asummary of our derivative financial instruments.The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as ofDecember 31, 2017, and 2016: (in thousands) Level 1 Level 2 Level 3 Fair Value December 31, 2017 Derivative financial instruments - asset $— $39 $— $39 Derivative financial instruments - liability $— $4,556 $— $4,556 Derivative deferred premiums - liability $— $— $401 $401 December 31, 2016 Derivative financial instruments - asset $— $1,976 $— $1,976 Derivative financial instruments - liability $— $4,336 $— $4,336 Derivative deferred premiums - liability $— $— $5,449 $5,449A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Year Ended December 31, (in thousands) 2017 2016 Balance of Level 3 at beginning of period $(5,449) $(9,973)Derivative deferred premiums - purchases — (516)Derivative deferred premiums - settlements 5,048 5,040 Balance of Level 3 at end of period $(401) $(5,449)Assets and Liabilities Measured at Fair Value on a Non-recurring BasisAsset Retirement ObligationsWe estimate the fair value of our ARO based on discounted cash flow projections using numerous estimates, assumptions and judgments regardingsuch factors as the existence of a legal obligation for ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates.See Note 7 in this section for a summary of changes in ARO.AcquisitionsThe estimated fair values of proved oil and natural gas properties acquired in business combinations are based on a discounted cash flow model andmarket assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount offuture development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates at the acquisitiondate. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and natural gas properties acquired is deemed to use Level 3inputs. See Note 3 in this section for further discussion of the Partnership’s acquisitions.ReservesWe calculate the estimated fair values of reserves and properties using valuation techniques consistent with the income approach, converting futurecash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of reserves, futureoperating and developmental costs, future commodity prices, a market-based weighted average cost of capital rate and the rate at which future cash flows arediscounted to estimate present value. We discount future values by a per annum62rate of 10% because we believe this amount approximates our long-term cost of capital and accordingly, is well aligned with our internal business decisions.The underlying commodity prices embedded in our estimated cash flows are the product of a process that begins with Level 1 NYMEX-WTI forward curvepricing, less Level 3 assumptions that include location, pricing adjustments and quality differentials. See Note 16 in this section for additional informationregarding our oil and natural gas reserves.ImpairmentThe need to test oil and natural gas assets for impairment may result from significant declines in sales prices or downward revisions in estimatedquantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the estimated undiscounted future net cash flows, animpairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. For the years ended December 31, 2017,and 2016, we recorded non-cash impairment of $24.7 million and $0.9 million, respectively. The majority of the 2017 non-cash impairment expense was dueto margin compression over the reserve life caused by lower future oil pricing and a higher cost profile on one of our Northeastern Oklahoma projects.Additional 2017 non-cash impairment expense occurred on one of our Permian projects where late-stage waterflood efforts in select wells in the field havelonger than anticipated response times to injection. The 2016 non-cash impairment resulted from a revision of reserve estimates for a property located in thePermian.When oil and natural gas properties are deemed to meet held-for-sale accounting criteria, non-cash impairment expense is recorded to reduce thecarrying amount of those assets to their fair value. For the year ended December 31, 2017, we recorded non-cash impairment of $0.3 million related to certainoil and natural gas properties located in Nolan County, Texas, deemed to meet held-for-sale accounting criteria as of December 31, 2017. See Note 15 in thissection for additional information regarding the divestiture. For the year ended December 31, 2016, we recorded non-cash impairment of $3.6 million relatedto the Hugoton divestiture that was deemed to meet held-for-sale accounting criteria as of June 30, 2016.Note 7. Asset Retirement ObligationsWe have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gasproduction operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring orsuccessfully drilling a well and determine our ARO by calculating the present value of estimated cash flow related to the estimated future liability.Determining the removal and future restoration obligation requires management to make estimates and judgments, including the ultimate settlementamounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount ofthe related long-lived asset. We review our assumptions and estimates of future ARO on an annual basis, or more frequently, if an event or circumstancesoccur that would impact our assumptions. To the extent future revisions to these assumptions impact the present value of the abandonment liability,management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. The liability is accreted eachperiod toward its future value. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets basedon proved developed reserves. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.For the years ended December 31, 2017, and 2016, our ARO were reported as “Asset retirement obligations” in our consolidated balance sheets.Changes in our ARO for the periods indicated are presented in the following table: Year Ended December 31, (in thousands) 2017 2016 Asset retirement obligations - beginning of period $11,331 $12,679 Liabilities incurred for new wells and interest 759 747 Liabilities settled upon plugging and abandoning wells (57) — Liabilities removed upon sale of wells (2,152) (2,827)Revision of estimates (75) 155 Accretion expense 520 577 Asset retirement obligations - end of period $10,326 $11,331 Note 8. DebtAt December 31, 2017, and 2016, we had outstanding borrowings under our revolving credit facility of $99.0 million and $122.0 million,respectively.The borrowing base of our revolving credit facility is collectively determined by our lenders based on the value of our proved oil and natural gasreserves using assumptions regarding future prices, costs and other variables. The borrowing base is subject to scheduled redeterminations in the spring andfall of each year with an additional redetermination, either at our request or at the request of the63lenders, during the period between each scheduled borrowing base redetermination. An additional borrowing base redetermination may be made at therequest of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract. The next regularly scheduledbi-annual redetermination is expected to occur in or around April 2018.Borrowings under the revolving credit facility bear interest at a floating rate based on, at our election, the greater of the prime rate of Wells FargoBank, National Association, the federal funds effective rate plus 0.50% and the one month adjusted London Interbank Offered Rate (“LIBOR”) plus 1.0%, allof which are subject to a margin that varies from 1.00% to 2.75% per annum according to the borrowing base usage (which is the ratio of outstandingborrowings and letters of credit to the borrowing base then in effect), or the applicable LIBOR plus a margin that varies from 2.00% to 3.75% per annumaccording to the borrowing base usage. For the year ended December 31, 2017, the average effective rate was 3.99%. Any unused portion of the borrowingbase will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for generalpartnership purposes and for funding distributions to our unitholders. The revolving credit facility includes customary affirmative and negative covenants,such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and payments, including distributions, andrequires us to maintain hedges covering projected production. If we fail to perform our obligations under these and other covenants, the revolving creditcommitments may be terminated and any outstanding indebtedness under the credit agreement, together with accrued interest, could be declared immediatelydue and payable.During the spring 2016 semi-annual redetermination and amendment to the credit agreement completed in May 2016, the effective borrowing base asof June 1, 2016, was reduced to $163.0 million and was comprised of a $110.0 million conforming tranche and a permitted overadvance of $53.0 million.The permitted overadvance was scheduled to mature on November 1, 2016. In addition, the amendment (i) required the Partnership to provide a monthlyexcess cash flow report; (ii) required the Partnership to make varied minimum monthly principal payments totaling $1.9 million through October 31, 2016;(iii) reduced the conforming borrowing base to $105.0 million upon the close of the Hugoton divestiture; (iv) allowed an additional non-scheduledborrowing base redetermination between September 1, 2016 and November 1, 2016 to be requested by any lenders; (v) increased the minimum collateralcoverage from 90% to 95% of proved reserves (and 100% of Proved Developed Producing reserves); (vi) required the Partnership to unwind and earlyterminate existing hedges covering production from July 2016 through September 2016 and add new at-the-market swap contracts to replace these hedgeterminations; and (vii) required the net proceeds from the Hugoton divestiture and from the early termination of hedge contracts to be applied to debtreduction.During August 2016, we completed a non-scheduled redetermination and amendment to the credit agreement in conjunction with our Permian Bolt-On acquisition. Among other changes, the amendment to the credit agreement increased the conforming borrowing base of the Partnership’s revolving creditfacility to $140.0 million as of August 11, 2016, modified the definition of “Indebtedness” to exclude the Preferred Units and modified the limitations onrestricted payments to specifically provide for the payment of cash distributions on the Preferred Units.During the fall 2016 semi-annual borrowing base redetermination of our revolving credit facility completed in October 2016, the lender groupreaffirmed the existing conforming borrowing base of $140.0 million effective October 28, 2016. There were no changes to the terms or conditions of thecredit agreement.During the spring 2017 semi-annual borrowing base redetermination of our revolving credit facility completed in May 2017, the lender groupreaffirmed the Partnership’s $140.0 million conforming borrowing base effective May 24, 2017. There were no changes to the terms or conditions of thecredit agreement.During the quarter ended September 30, 2017, we were not in compliance with our leverage ratio calculation. On November 10, 2017, the Partnershipreceived a waiver from the Administrative Agent and the Lenders of our revolving credit facility waiving the noncompliance through December 15, 2017. OnDecember 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 NolanCounty divestiture on January 9, 2018, be applied to the borrowings outstanding. See Note 3 and 15 in this section for more information regarding thesedivestitures.On January 31, 2018, Amendment 12 to the credit agreement was executed, extending the maturity of our credit facility from November 2018 untilNovember 2020, and increasing the borrowing base of the Partnership’s revolving credit facility to $125.0 million. The lenders also waived any default orevent of default that occurred as a result of the Partnership’s failure to maintain the required leverage ratios for the quarter ended September 30, 2017. Theamendment also required the Partnership to have a minimum liquidity of 20% prior to making any distributions to the Preferred Unitholders.64Note 9. Commitment and ContingenciesLeasesWe lease corporate office space in Tulsa, Oklahoma, and Abilene, Texas. We were also allocated office rent from Mid-Con Energy Operating throughAugust 2016 for office space in Dallas, Texas. For the years ended December 31, 2017, and 2016, total lease expenses were $0.3 million and $0.4 million,respectively. These expenses are included in general and administrative expenses in our consolidated statements of operations.Future minimum lease payments under the non-cancellable operating leases are presented in the following table: (in thousands) 2018 $489 2019 413 2020 418 2021 423 Total $1,743Services AgreementWe are party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provides certain services to usincluding management, administrative and operational services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis,for the allocable expenses it incurs in its performance under the services agreement. See Note 11 in this section for additional information.Employment AgreementsOur general partner has entered into employment agreements with Charles R. Olmstead, Executive Chairman of the Board, and Jeffrey R. Olmstead,President and Chief Executive Officer. The employment agreements automatically renew for one-year terms unless either we or the employee gives writtennotice of termination by the preceding February. Pursuant to the employment agreements, each employee will serve in his respective position with ourgeneral partner, as set forth above, and has duties, responsibilities and authority as the Board may specify from time to time, in roles consistent with suchpositions that are assigned to them. The agreement stipulates that if there is a change of control, termination of employment, with cause or without cause, ordeath of the executive certain payments will be made to the executive officer. These payments, depending on the reason for termination, currently range from$0.3 million to $0.6 million, including the value of vesting of any outstanding units.LegalWe are party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management and our GeneralCounsel, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or otherindemnification arrangements will not have a material adverse effect on our financial position, results of operations or cash flows.Note 10. EquityCommon UnitsAt December 31, 2017, and 2016, the Partnership’s equity consisted of 30,090,463 and 29,912,230 common units, respectively, representing a 98.8%limited partnership interest in us.On May 5, 2015, we entered into an Equity Distribution Agreement to sell, from time to time through or to the Managers (as defined in the agreement),up to $50.0 million in common units representing limited partner interests. In connection with the Preferred Units agreement described below, the Partnershipsuspended sales of common units pursuant to the Equity Distribution Agreement effective as of the closing date until the fifth anniversary of the closing dateof the Preferred Units purchase agreement, without the consent of a majority of the holders of the outstanding Preferred Units.Our Partnership Agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of aquarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash fromworking capital borrowings. As of December 31, 2017, cash distributions to our common units continued to be indefinitely suspended. Our credit agreementstipulates written consent from our lenders is required in order to reinstate65common unit distributions. Management and the Board will continue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determiningfuture distributions. The suspension of common unit cash distributions is designed to preserve liquidity and reallocate excess cash flow towards capitalexpenditure projects and debt reduction to maximize long-term value for our unitholders. There is no assurance as to future cash distributions since they aredependent upon our projections for future earnings, cash flows, capital requirements, financial conditions and other factors. There were no common unitdistributions for the years ended December 31, 2017, and 2016.Class A Preferred UnitsOn August 11, 2016, we completed a private placement of 11,627,906 Class A Preferred Units for an aggregate offering price of $25.0 million. TheClass A Preferred Units were issued at a price of $2.15 per Class A Preferred Unit (the “Class A Unit Purchase Price”). Proceeds from this issuance were used tofund the Permian Bolt-On acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. Wereceived net proceeds of $24.6 million (net of issuance costs of $0.4 million) in connection with the issuance of these Class A Preferred Units. We allocatedthese net proceeds, on a relative fair value basis, to the Class A Preferred Units ($18.6 million) and the beneficial conversion feature ($6.0 million). Abeneficial conversion feature is defined as a non-detachable conversion feature that is in the money at the commitment date. Per accounting guidance, we arerequired to allocate a portion of the proceeds from the Class A Preferred Units to the beneficial conversion feature based on the intrinsic value of thebeneficial conversion feature. The intrinsic value is calculated at the commitment date based on the difference between the fair value of the common units atthe issuance date (number of common units issuable at conversion multiplied by the per-share value of our common units at the issuance date) and theproceeds attributed to the Class A Preferred Units. We record the accretion attributed to the beneficial conversion feature as a deemed distribution using theeffective yield method over the five year period prior to the effective date of the holders conversion right. Accretion of the beneficial conversion feature was$1.1 million and $0.5 million for the years ended December 31, 2017, and 2016, respectively.The holders of our Class A Preferred Units are entitled to certain rights that are senior to the rights of holders of common units, such as rights todistributions and rights upon liquidation of the Partnership. We pay holders of the Class A Preferred Units a cumulative, quarterly cash distribution on allClass A Preferred Units then outstanding at an annual rate of 8.0%, or in the event that the Partnership’s existing secured indebtedness prevents the paymentof a cash distribution to all holders of the Class A Preferred Units, in kind (additional Class A Preferred Units), at an annual rate of 10.0%. Such distributionswill be paid for each such quarter within 45 days after such quarter end, or as otherwise permitted to accumulate pursuant to the Partnership Agreement. As ofDecember 31, 2017, all Class A Preferred Unit distributions have been paid in cash. No payment or distribution on common units for any quarter is permittedprior to the payment in full of the Class A Preferred Units distribution (including any outstanding arrearages). At December 31, 2017, the Partnership hadaccrued $1.0 million for the third and fourth quarter 2017 distributions that are to be paid in February 2018. The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2017: Date Paid Period Covered Distribution perUnit Total Distributions(in thousands) February 14, 2017 October 1, 2016 - December 31, 2016 $0.043 $500 May 15, 2017 January 1, 2017 - March 31, 2017 $0.043 $500 August 14, 2017 April 1, 2017 - June 30, 2017 $0.043 $500 The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2016: Date Paid Period Covered Distribution perUnit Total Distributions(in thousands) November 14, 2016 August 11, 2016 - September 30, 2016 $0.024 $279Prior to the five year anniversary of the closing date, each holder of the Class A Preferred Units has the right, subject to certain conditions, to convertall or a portion of their Class A Preferred Units into common units representing limited partner interests in the Partnership on a one-for-one basis, subject toadjustment for splits, subdivisions, combinations and reclassifications of the common units. Upon conversion of the Class A Preferred Units, the Partnershipwill pay any distributions (to the extent accrued and unpaid as of the then most recent Class A Preferred Units distribution date) on the converted units incash. The registration statement registering resales of common units issued or to be issued upon conversion of the Class A Preferred Units was declaredeffective by the SEC on June 14, 2017.Allocations of Net Income or LossNet income or loss is allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss isallocated to the limited partner unitholders net of Preferred Unit distributions, including accretion of the Preferred Unit beneficial conversion feature. In theevent of net income, diluted net income per partner unit reflects the potential dilution of non-vested restricted stock awards and the conversion of PreferredUnits.66Note 11. Related Party TransactionsAgreements with AffiliatesThe following agreements were negotiated among affiliated parties and, consequently, were not the result of arm’s length negotiations. The followingis a description of those agreements that have been entered into with the affiliates of our general partner and with our general partner.Services AgreementWe are party to a services agreement with our affiliate, Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provides certainservices to us, including management, administrative and operational services. The operational services include marketing, geological and engineeringservices. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performanceunder the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons whoperform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. These expenses were included in general andadministrative expenses in our consolidated statements of operations.Operating AgreementsWe, along with various third parties with an ownership interest in the same property, are parties to standard oil and natural gas joint operatingagreements with our affiliate, Mid-Con Energy Operating. We and those third parties pay Mid-Con Energy Operating overhead associated with operating ourproperties and for its direct and indirect expenses that are chargeable to the wells under their respective operating agreements. The majority of these expenseswere included in lease operating expenses in our consolidated statements of operations.Oilfield ServicesWe are party to operating agreements, pursuant to which our affiliate, Mid-Con Energy Operating, bills us for oilfield services performed by ouraffiliates, ME3 Oilfield Service and ME2 Well Services. These amounts were either included in lease operating expenses in our consolidated statements ofoperations or were capitalized as part of oil and natural gas properties in our consolidated balance sheets.The following table summarizes the affiliates’ transactions for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 Services agreement $2,443 $3,403 Operating agreements 6,509 6,221 Oilfield services 3,377 3,058 $12,329 $12,682At December 31, 2017, we had a net payable to our affiliate, Mid-Con Energy Operating, of $1.6 million, comprised of a joint interest billing payableof $1.4 million and a payable for operating services of $0.2 million. At December 31, 2016, we had a net payable to our affiliate Mid-Con Energy Operatingof $3.4 million, comprised of a joint interest billing payable of $2.8 million and a payable for operating services of $0.6 million. These amounts wereincluded in accounts payable-related parties in our consolidated balance sheets.Note 12. Credit RiskCredit risk relates to the risk of loss resulting from non-performance of non-payment by counterparties under the terms of their contractual obligations,thereby impacting the amount and timing of expected cash flows. Financial instruments which potentially subject us to credit risk consist principally of cashbalances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, mayexceed the federally insured limits. We have not experienced any significant losses from such investments.For the year ended December 31, 2017, sales of oil and natural gas to four purchasers accounted for 99% of our sales. At December 31, 2017, thesepurchasers accounted for 98% of our outstanding oil and natural gas accounts receivable. For the year ended December 31, 2016, sales of oil and natural gasto four purchasers accounted for 94% of our sales. At December 31, 2016, these purchasers accounted for 95% of our outstanding oil and natural gas accountsreceivable. We believe that the loss of any one purchaser would not have a material adverse effect on our ability to sell our oil and natural gas production asother purchasers would be accessible. We have not experienced any significant losses due to uncollectible accounts receivable from these purchasers.67Note 13. Employee Benefit PlansIn 2011, our general partner adopted the Long-Term Incentive Program which is intended to promote the interests of the partnership by providing toemployees, officers, consultants and directors of our general partner and our other affiliates, including Mid-Con Energy Operating and ME3 Oilfield Service,grants of restricted units, phantom units, unit appreciation rights, distribution equivalent rights and other unit based awards to encourage superiorperformance. The Long-Term Incentive Program is also intended to enhance the ability of the general partner and our affiliates, to attract and retain theservices of individuals who are essential for the growth and profitability of the partnership and to encourage them to devote their best efforts to advancing thebusiness of the partnership.The Long-Term Incentive Program is administered by Charles R. Olmstead and Jeffrey R. Olmstead, the voting members of our general partner, andawards are approved by the Board. Except as set forth in the employment agreements of the executive officers of our general partner, there is no set formulafor granting awards to our employees, officers, consultants and directors of our general partner and our affiliates. In determining whether to grant awards andthe amount of any awards, the administrators take into consideration the performance of the Partnership along with discretionary factors such as theindividual’s current and expected future performance, level of responsibility, retention considerations and the total compensation package. See Note 4 in thissection for additional information regarding awards granted under the Long-Term Incentive Program.Note 14. Income TaxesWe do not pay federal income taxes, as our profits or losses are reported to the taxing authorities by our individual partners.Note 15. Subsequent EventsNolan County DivestitureOn January 9, 2018, we entered a binding letter agreement to sell certain Permian oil and natural gas proved properties in Nolan County, Texas, forcash consideration of $1.6 million, subject to customary post-closing sale price adjustments. Per the agreement, the effective date of the sale was November 1,2017. Proceeds from the divestiture were used to reduce borrowings outstanding under the Partnership’s revolving credit facility.House Creek AcquisitionOn January 16, 2018, we acquired multiple oil and natural gas properties located in Campbell County, Wyoming, for cash consideration of $1.5million, subject to customary post-closing sale price adjustments. The effective date of the acquisition was September 1, 2017.Credit Facility AmendmentOn January 31, 2018, Amendment 12 to the credit agreement was executed, extending the maturity of our credit facility from November 2018 untilNovember 2020, and increasing the borrowing base of the Partnership’s revolving credit facility to $125.0 million. The lenders also waived any default orevent of default that occurred as a result of the Partnership’s failure to maintain the required leverage ratios for the quarter ended September 30, 2017. Theamendment also required the Partnership to have minimum liquidity of 20% prior to making any distributions to the Preferred Unit holders.Class B Preferred Units OfferingOn 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. Wereceived cash proceeds of $15.0 million in connection with the issuance of these Class B Preferred Units. The Partnership used a portion of the proceeds fromthe offering to fund the acquisition of certain properties in Campbell and Converse Counties, Wyoming, and any excess was used to reduce borrowings underour revolving credit facility. The Class B Preferred Units were issued at a price of $1.53 per Preferred Unit. The Partnership will pay holders of the Class BPreferred Units a cumulative, quarterly distribution in cash at an annual rate of 8.0%, or under certain circumstances, in additional Class B Preferred Units, atan annual rate of 10.0%. At any time after the six month anniversary and prior to August 11, 2021, each holder of the Preferred Units may elect to convert allor any portion of their Class B Preferred Units into common units representing limited partner interests in the Partnership on a one-for-one basis. On August11, 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 PurchasePrice, and any remaining Class B Preferred Units will thereafter be converted to common units on a one-for-one basis.68Pine Tree AcquisitionOn January 31, 2018, we acquired multiple oil and natural gas properties located in Campbell and Converse Counties, Wyoming, for cashconsideration of $8.6 million, subject to customary post-closing sale price adjustments. The effective date of the acquisition was September 1, 2017. Thepurchase price was funded by the Class B Preferred Unit Offering described above.DistributionsOn January 31, 2018, the Partnership announced that the Board declared a Class A Preferred Unit cash distribution for the third and fourth quarters of2017, 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, waspaid on February 14, 2018 to holders of record as of the close of business on February 7, 2018.Equity AwardsDuring the first quarter of 2018, the Board authorized the issuance of 87,832 unrestricted common units and 389,500 equity-settled phantom units.Note 16. Supplementary InformationSupplementary Oil and Natural Gas ActivitiesCosts incurred in oil and natural gas property acquisitions and development activities are as follows: Year Ended December 31, (in thousands) 2017 2016 Property acquisition costs: Proved $4,665 $18,722 Unproved 369 — Exploration — — Development 9,947 6,963 Asset retirement obligations 684 902 Total costs incurred $15,665 $26,587Estimated Proved Oil and Natural Gas Reserves (Unaudited)The Partnership’s proved oil and natural gas reserves are all located in the United States. The proved oil and natural gas reserves for the years endedDecember 31, 2017, and 2016, were prepared by our reservoir engineers and audited by Cawley, Gillespie & Associates, Inc., independent third partypetroleum consultants. These reserve estimates have been prepared in compliance with the rules of the SEC. We emphasize that reserve estimates areinherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, theestimates are expected to change as future information becomes available.69An analysis of the change in estimated quantities of oil and natural gas reserves are presented below for the periods indicated: Oil(MBbls) Natural Gas(MMcf) MBoe Proved developed and undeveloped reserves: As of December 31, 2015 21,114 6,827 22,252 Revisions of previous estimates (1) 58 (262) 14 Extensions, discoveries and other additions — — — Purchases of reserves in place (2) 1,517 211 1,552 Sales of reserves in place (3) (3,093) (98) (3,109)Production (1,386) (554) (1,478)As of December 31, 2016 18,210 6,124 19,231 Revisions of previous estimates (1) 2,355 168 2,383 Extensions, discoveries and other additions(4) 69 — 69 Purchases of reserves in place (5) 1,607 459 1,684 Sales of reserves in place (6) (2,522) (38) (2,529)Production (1,209) (431) (1,281)As of December 31, 2017 18,510 6,282 19,557 Proved developed reserves: December 31, 2016 11,733 4,141 12,423 December 31, 2017 13,512 4,586 14,276 Proved undeveloped reserves: December 31, 2016 6,477 1,983 6,808 December 31, 2017 4,998 1,696 5,281(1) Revisions represent changes in the previous reserves estimates, either upward or downward, resulting from new information normally obtained from developmentdrilling and production history or resulting from a change in economic factors, such a commodity prices, operating costs or development costs.(2) Represents the purchase of proved reserves as part of our Permian Bolt-On acquisition.(3) Decrease due to the sale of our Hugoton oil and natural gas properties.(4) Extension of our Hardrock Field in the Texas core area as a result of drilling two successful step out wells in 2017.(5) Represents the purchase of proved reserves as part of our Oklahoma Wheatland acquisition.(6) Decrease due to the sale of our Southern Oklahoma oil and natural gas properties.The change in quantities of proved reserves from December 31, 2015, to December 31, 2016, was due in part to commodity price decreases whichshortened the economic lives of certain producing properties and caused certain development projects to become uneconomic which had an adverse impacton our proved reserves estimates, resulting in downward reserve revisions of 1,801 MBoe in 2016. In response to the continued decrease in commodity pricesthroughout 2016, we further refined our development plans to concentrate on our Northeastern Oklahoma and Permian areas. This included infill drills andrecompletions resulting in positive revisions in production performance of 569 MBoe. In addition, we saw positive oil production responses to waterinjection in our Northeastern Oklahoma and Permian areas, resulting in upward revisions to our proved reserves of 1,246 MBoe. During 2016, the acquisitionof the Permian Bolt-On properties resulted in a positive revision of 1,552 MBoe, and the divestiture of our Hugoton area properties resulted in a downwardrevision of 3,109 MBoe.The increase in quantities of proved reserves from December 31, 2016, to December 31, 2017, was due in part to commodity price increases of 1,309MBoe which extended the economic lives of certain producing properties, offset in part by downward revisions from certain recent results and developmentplans. Increased oil production was seen as a response to water injection in our Oklahoma and Texas core areas resulting in upward revisions to our provedreserves of 1,074 MBoe. Positive outcomes from step out drilling locations in the Texas core area resulted in an extension within our Hardrock Field andgenerated an increase in proved reserves of 69 MBoe. During 2017, the acquisition of the Wheatland properties resulted in a positive revision of 1,684MBoe, and the divestiture of our Southern Oklahoma properties resulted in a decrease in proved reserves of 2,529 MBoe.Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors andassumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, developmentand operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gainedfrom production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially fromthe amounts estimated.70Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Unaudited)The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less futuredevelopment, production, plugging and abandonment costs, discounted at the rate prescribed by the SEC. The standardized measure of discounted future netcash flow does not purport to be, nor should it be interpreted to represent, the fair market value of our proved oil and natural gas reserves. The followingassumptions have been made: •in the determination of future cash inflows, sales prices used for oil and natural gas for the years ended December 31, 2017, and 2016, wereestimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-monthprice for each month in such period; •future costs of developing and producing the proved oil and natural gas reserves were based on costs determined at each such period-end,assuming the continuation of existing economic conditions, including abandonment costs; •no future income tax expenses are computed for Mid-Con Energy Partners, because we are a non-taxable entity; and •future net cash flows were discounted at an annual rate of 10%.The standardized measure of discounted future net cash flow relating to estimated proved oil and natural gas reserves is presented below for theperiods indicated: Year Ended December 31, (in thousands) 2017 2016 Future cash inflows $927,473 $741,077 Future production costs (444,673) (389,138)Future development costs, including abandonment costs (50,868) (65,195)Future net cash flow 431,932 286,744 10% discount for estimated timing of cash flow (224,719) (129,459)Standardized measure of discounted cash flow $207,213 $157,285The prices utilized in calculating our total proved reserves were $51.34 and $42.75 per Bbl of oil and $2.98 and $2.49 per MMBtu of natural gas forDecember 31, 2017, and 2016, respectively. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses ordeductions or other factors affecting the price received at the wellhead. Average adjusted prices used were $49.34 and $40.03 per Bbl of oil and $2.27 and$1.99 per Mcf of natural gas for December 31, 2017, and 2016, respectively. Adjusted natural gas price includes the sale of associated NGLs. We do notextract NGLs from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasersextract NGLs from the natural gas stream sold by us to them, we have no ownership in such NGLs; therefore, we do not report NGLs in our production orproved reserves. All wellhead prices are held flat over the life of the properties for all reserve categories.Changes in the standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is presented below for theperiods indicated: Year Ended December 31, (in thousands) 2017 2016 Standardized measure of discounted future net cash flow, beginningof year $157,285 $191,420 Changes in the year resulting from: Sales, less production costs (33,994) (30,513)Revisions of previous quantity estimates 28,132 133 Extensions, discoveries and improved recovery 3,168 — Net change in prices and production costs 61,504 (16,138)Net change in income taxes — — Changes in estimated future development costs 5,173 22,685 Previously estimated development costs incurred during the year 9,726 3,526 Purchases of reserves in place 13,826 22,223 Sales of reserves in place (10,420) (11,124)Accretion of discount 15,729 19,142 Timing differences and other (42,916) (44,069)Standardized measure of discounted future net cash flow, end of year $207,213 $157,285 71ITEM 9.CHANGES IN AND DISAGREEMETS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURENone.ITEM 9A.CONTROLS AND PROCEDURESEvaluation of Disclosure Controls and Procedures.As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our chief executive officer(principal executive officer) and chief accounting officer (as principal financial officer), the effectiveness of our disclosure controls and procedures (asdefined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2017. Our disclosure controls and procedures are designed to providereasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated toour management, including our chief executive officer and chief accounting officer, as appropriate, to allow timely decisions regarding required disclosureand is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on this evaluation, our chiefexecutive officer and chief accounting officer have concluded that our disclosure controls and procedures were effective as of the end of the period coveredby this Form 10-K.Management’s Report on Internal Control over Financial ReportingMANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTINGManagement, including our Chief Executive Officer and Chief Accounting Officer, is responsible for establishing and maintaining adequate internalcontrol over our financial reporting. Our internal control system was designed to provide reasonable assurance to our Management and Directors regardingthe preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may notprevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may becomeinadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control – IntegratedFramework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concludedthat Mid-Con Energy Partners, LP’s internal control over financial reporting was effective as of December 31, 2017. /s/ Jeffrey R. Olmstead /s/ Sherry L. MorganJeffrey R. OlmsteadChief Executive Officer Sherry L. MorganChief Accounting Officeras Principal Financial OfficerFebruary 28, 2018Change in Internal Controls Over Financial ReportingThere were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the ExchangeAct) that occurred during the period covered by this Form 10-K that have materially affected, or are reasonably likely to materially affect, our internal controlover financial reporting.In the course of our ongoing preparations for making management’s report on internal control over financial reporting as required by Section 404 ofthe Sarbanes-Oxley Act of 2002, from time to time we have identified areas in need of improvement and have taken remedial actions to strengthen theaffected controls as appropriate. We make these and other changes to enhance the effectiveness of our internal control over financial reporting, which do nothave a material effect on our overall internal control.ITEM 9B.OTHER INFORMATIONNone.72PART IIIITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEAs is the case with many publicly traded partnerships, we do not directly employ officers, directors or employees. Our operations and activities aremanaged by our general partner. References to our officers and Board of Directors therefore refer to the officers and Board of Directors of our general partner.Our general partner is controlled by Charles R. Olmstead and Jeffrey R. Olmstead, (“the voting members of our general partner”).Our general partner is not elected by our unitholders and is not subject to re-election on an annual or other continuing basis in the future. In addition,our unitholders are not entitled to elect the directors of our general partner, nor are they directly or indirectly entitled to participate in our management oroperations. Further, our Partnership Agreement, like many master limited Partnership Agreements, contains provisions that substantially restrict the fiduciaryduties that our general partner would otherwise owe to our unitholders under Delaware law.The Board has eight members. The NASDAQ listing rules do not require a listed limited partnership, like us, to have a majority of independentdirectors on the Board or to establish a compensation committee or a nominating and corporate governance committee. We are, however, required to have anaudit committee of at least three members, all of whom are required to meet the independence and experience standards established by the NASDAQ listingrules and SEC rules.All of the executive officers of our general partner are also officers and/or directors of Mid-Con Affiliates. The executive officers allocate their timebetween managing our business and affairs and the business and affairs of Mid-Con Affiliates. In addition, employees of Mid-Con Energy Operating providemanagement, administrative and operational services to us pursuant to the services agreement, but they also provide these services to Mid-Con Affiliates.Directors and Executive OfficersThe following table sets forth certain information regarding the current directors and executive officers of our general partner. At February 28, 2018,the average tenure of the individuals listed below was approximately four years since the Initial Public Offering in December 2011. Name Age Position with Mid-Con Energy GP, LLCCharles R. “Randy” Olmstead 69 Executive Chairman of the BoardJeffrey R. Olmstead 41 President, Chief Executive Officer and DirectorCharles L. McLawhorn III 41 Vice President, General Counsel and Corporate SecretarySherry L. Morgan 50 Chief Accounting OfficerPeter Adamson III (1) 76 DirectorC. Fred Ball Jr. (2) 73 DirectorJohn W. Brown (2) 71 DirectorWilkie S. Colyer Jr. 33 DirectorPeter A. Leidel 61 DirectorCameron O. Smith (1) 67 Director(1)Member of the audit committee and the conflicts committee.(2)Member of the audit committee.The members of our Board are appointed for one-year terms by the voting members of our general partner, and hold office until the earlier of theirdeath, resignation, removal or disqualification or until their successors have been appointed and qualified. The executive officers serve at the discretion ofthe Board. All of our executive officers also serve as executive officers of the Mid-Con Affiliate. Charles R. Olmstead and Jeffrey R. Olmstead are father andson, respectively. There are no other family relationships among our executive officers and directors.Charles R. “Randy” Olmstead serves as Executive Chairman of the Board. Mr. Olmstead previously served as Chief Executive Officer and Chairmanof the Board of our general partner and Mid-Con Energy III, LLC, from June 2011 until August 2014. Mr. Olmstead served as President, Chief FinancialOfficer and Chairman of the Board of Mid-Con Energy I, LLC, from its formation in 2004 and of Mid-Con Energy II, LLC, from its formation in 2009 untilboth entities were merged into the Partnership in December 2011. He has been President, Chief Financial Officer and Chairman of the Board of Mid-ConEnergy Operating since its incorporation in 1986. Prior to that, Mr. Olmstead was general manager for LB Jackson Drilling Company from 1978 to 1980 andworked in public accounting for Touche Ross & Co. from 1974 to 1978 as an oil and natural gas tax consultant. Mr. Olmstead graduated with Bachelors ofBusiness Administration degrees in Finance and Accounting from the University of Oklahoma before serving three years in the US Navy. Mr. Olmstead bringsextensive management and operational experience in the oil and natural gas industry, along with his leadership skills to our Board.73Jeffrey R. Olmstead, President, Chief Executive Officer, and Director, previously served as President, Chief Financial Officer of our general partner andMid-Con Energy III, LLC, from June 2011 until August 2014. Mr. Olmstead was a member of the Board of Mid-Con Energy I, LLC, and Mid-Con Energy II,LLC, from 2007 until both entities were merged into the Partnership in December 2011. Mr. Olmstead previously served as Chief Financial Officer and VicePresident of Primexx Energy Partners, Ltd., a privately held exploration and production company, from May 2010 until July 2011. From August 2006 untilMay 2010, Mr. Olmstead served as an Assistant Vice President at Bank of Texas/Bank of Oklahoma. Mr. Olmstead holds a Bachelor of Engineering degree inElectrical Engineering and Math from Vanderbilt University and a Master of Business Administration degree from the Owen School of Business at VanderbiltUniversity. Mr. Olmstead brings knowledge of the oil and natural gas industry and his finance background provides a critical resource to our Board.Charles L. McLawhorn III, Vice President, General Counsel and Corporate Secretary of our general partner, became an officer in April 2016. FromAugust 2009 to March 2016, Mr. McLawhorn held a series of positions with increasing responsibility, including Assistant General Counsel and CorporateSecretary, at Samson Resources Corporation. Earlier in his career, Mr. McLawhorn was in private practice with McAfee & Taft from 2002 to 2009.Mr. McLawhorn graduated with a Bachelor of Science degree in Zoology from the University of Oklahoma and a Juris Doctor degree from the University ofOklahoma College of Law.Sherry L. Morgan, Chief Accounting Officer and acting Principal Financial Officer, became an officer in July 2015, and previously served as ourAssistant Controller from July 2008 until July 2015. Prior to joining us, Ms. Morgan served as Controller at Shamrock Oil & Gas, Inc., from 2006 to 2008.She also served as Controller for Nadel and Gussman, LLC, during 2006. Ms. Morgan served as Reporting and Joint Interest Coordinator at NewfieldExploration Mid-Continent, Inc., from 2000 to 2005. Previously, she was Assistant Controller at both Lariat Petroleum, Inc., and First Credit Solutions. Ms.Morgan began her career as an auditor at Deloitte and Touche, LLP. Ms. Morgan earned her Bachelor of Science in Business Administration with a degree inAccounting from Oklahoma State University. She is a Certified Public Accountant and a Certified Management Accountant.Peter Adamson III, Director, is the chairman of the audit committee. Mr. Adamson is currently the managing member of Autumn Glory Partners, LLC, aprivate consulting firm. Prior to Autumn Glory Partners, LLC, Mr. Adamson was a founder of Adams Hall Asset Management, LLC, a Tulsa, Oklahoma, basedregistered investment advisor with over $1 billion under management and still serves as a consultant. Prior to forming Adams Hall in 1997, Mr. Adamson wasan owner and principal of Houchin, Adamson & Co., Inc., a registered broker-dealer formed in 1980. Mr. Adamson is founding co-investor and advisor toHorizon Well Logging, a leading provider of geological field services. Mr. Adamson serves on the advisory board of the Michel F. Price College of Businessat the University of Oklahoma and serves on the University of Oklahoma asset oversight committee. Mr. Adamson received his Bachelor of BusinessAdministration degree in Accounting from the University of Oklahoma. Mr. Adamson brings a breadth knowledge across the disciplines of finance andaccounting to our Board.C. Fred Ball Jr., Director, currently serves as Chief Operating Officer of Spyglass Trading, LP. Mr. Ball retired in January 2015 as Senior Chairman ofthe Board for Bank of Texas, a division of BOK Financial Corporation. During his 17 year tenure at Bank of Texas, Mr. Ball was elected to various executivepositions including President, Chief Executive Officer and Chairman. Prior to Bank of Texas, he served as President of Comerica Securities, Inc., a subsidiaryof Comerica Incorporated in Detroit. Mr. Ball currently serves on the Boards of BOK Financial Corporation, the National Teachers Associates Life InsuranceCompany, where he is also a member of the audit committee, and Southern Methodist University, where he resides on the Executive Board of the Edwin L.Cox School of Business. Mr. Ball earned his Bachelor of Science in Engineering and Master of Business Administration from Southern Methodist University.Mr. Ball brings extensive insights and the knowledge of finance and banking to our Board.John W. Brown, Director, has served as Chairman of Par Investments LLC, a private investment firm focused on energy related investments, since June2005. Since July 1991, Mr. Brown has served as the General Partner of Premier Capital, Ltd., a private energy focused investment banking firm that has beenan advisor of energy transactions in excess of $400 million since 2003. Mr. Brown served on the Board of Directors of Halcon Resources from March 2016through September 2016. From 2001 to 2003, Mr. Brown served as a Director of Friedman, Billings, Ramsey Group, a publicly traded full service bankingfirm focused on energy investment banking transactions. Prior to that, Mr. Brown served as an Associate at EnCap Investments, L.C., from 2000 to 2001; wasthe Founder and General Partner of WesAl Capital, Ltd., a private energy investment banking firm with the late William E. Simon, former Secretary of theTreasury, and Alvin Shoemaker, former Chairman of First Boston from 1986 to 1991; and was the Founder, and President of Westwood Resources Company,a privately held independent oil and gas company, from 1981 to 1984. Mr. Brown practiced law from 1973 until 1981. He earned a Bachelor of Arts Degreefrom Southern Methodist University and a Juris Doctor Degree and Masters of Laws Degree from Southern Methodist University Law School. Mr. Brownbrings extensive experience and knowledge of finance and energy to our Board.Wilkie S. Colyer Jr., Director, currently serves as a Principal for Goff Capital, Inc. (“Goff Capital”), the family office of John C. Goff, which indirectlyholds a significant number of the Partnership’s Preferred Units. Since joining Goff Capital in 2007, Mr. Colyer has led or played a material role in public andprivate investments in sectors including energy, financial services, and real estate, among others. Mr. Colyer received a Bachelor of Arts in Economics fromthe University of Texas at Austin. Mr. Colyer holds the Chartered74Financial Analyst (“CFA”) designation and is a member of the CFA Society of Dallas-Fort Worth. Mr. Colyer brings extensive insight into energy and financeto our Board.Peter A. Leidel, Director, is a founder and principal of Yorktown Partners, LLC, which was established in September 1990. Yorktown Partners, LLC, isthe manager of private investment partnerships that invest in the energy industry. Mr. Leidel has been a member of the Boards of Mid-Con Energy III, LLC,and Mid-Con Energy Operating since June 2011. Mr. Leidel was a member of the Boards of both Mid-Con Energy I, LLC, from its formation in 2004 and ofMid-Con Energy II, LLC, from its formation in 2009 until both entities were merged into the Partnership in December 2011. Previously, he was a partner ofDillon, Read & Co. Inc., held corporate treasury positions at Mobil Corporation, worked for KPMG and for the U.S. Patent and Trademark Office. Mr. Leidelis a director of certain non-public companies in the energy industry in which Yorktown holds equity interests. Mr. Leidel earned a Bachelor of BusinessAdministration degree in Accounting from the University of Wisconsin and a Master of Business Administration from the Wharton School at the Universityof Pennsylvania. Mr. Leidel brings extensive private experience within and perspective on the energy sector to our Board.Cameron O. Smith, Director, is also chairman of the conflicts committee. From 2008 until December 2009, Mr. Smith served as a Senior ManagingDirector of Rodman & Renshaw, LLC, and as Head of The Rodman Energy Group, a sector vertical within Rodman & Renshaw, LLC. Mr. Smith retired fromThe Rodman Energy Group in December 2009. Mr. Smith founded, and from 1992 to 2008, served as a Senior Managing Director of COSCO CapitalManagement, LLC, an investment bank focused on private oil and natural gas corporate and project financing until Rodman & Renshaw, LLC, a full serviceinvestment bank, purchased the business and assets of COSCO Capital Management, LLC. Mr. Smith founded and ran Taconic Petroleum Corporation, anexploration company headquartered in Tulsa, Oklahoma, from 1978 to 1991. Mr. Smith served as exploration geologist, officer and director of several privatefamily and public client companies from 1975 to 1985. Mr. Smith graduated with a Bachelor of Arts in Art History from Princeton University and a Master ofScience degree in Geology from Pennsylvania State University. Mr. Smith brings extensive knowledge of the oil and natural gas industry, along withexpertise in investment banking, to our Board.Committees of the Board of DirectorsThe Board of Mid-Con Energy GP, has an audit committee and a conflicts committee, but does not have a compensation committee. The NASDAQlisting rules do not require a listed limited partnership to establish a compensation committee or a nominating and corporate governance committee. Equitygrants to directors and employees are administered by the voting members of the general partner and approved by the Board.Audit CommitteeThe audit committee consists of Messrs. Adamson, Ball, Brown and Smith, with Mr. Adamson serving as committee chairman. Our Board hasaffirmatively determined that each member of the audit committee meets the independence and experience standards established by the NASDAQ listingrules and the rules of the SEC. Our Board has also reviewed the financial expertise of Mr. Adamson and affirmatively determined that he is an “auditcommittee financial expert,” as determined by the rules of the SEC. Our Board has adopted a written charter for our audit committee which is available on,and may be printed from, our website at www.midconenergypartners.com and is also available from the corporate secretary of Mid-Con Energy GP.The audit committee held four quarterly meetings in 2017. The audit committee assists the Board in its oversight of the integrity of our financialstatements, compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to retain orterminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by ourindependent registered public accounting firm and pre-approve any non-audit services and tax services to be rendered by our independent registered publicaccounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accountingfirm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.Conflicts CommitteeThe conflicts committee consists of Messrs. Smith and Adamson, both of whom meet the independence standards established by the NASDAQ listingrules and rules of the SEC. The conflicts committee has the authority to review specific matters that may present a conflict of interest in order to determine ifthe resolution of such conflict is “fair and reasonable” for our unitholders. In making such determination, the conflicts committee has the authority to engageadvisors to assist it in carrying its duties. The conflicts committee did not hold any meetings in 2017.Board Leadership Structure and Role in Risk OversightLeadership of our Board is vested in the Chairman of the Board. Although our Chief Executive Officer currently does not serve as Chairman of theBoard, we currently have no policy prohibiting our current, or any future Chief Executive Officer, from serving as75Chairman of the Board. The Board, in recognizing the importance of its ability to operate independently, determined that separating the roles of Chairman ofthe Board and Chief Executive Officer is advantageous for us and our unitholders at this time. Our Board has also determined that having the Chief ExecutiveOfficer serve as a director will enhance understanding and communication between management and the Board, allow for better comprehension andevaluation of our operations and ultimately improve the ability of the Board to perform its oversight role.The management of enterprise-level risk is the process of identifying, managing and monitoring events that present opportunities and risks withrespect to the creation of value for our unitholders. The Board has delegated to management the primary responsibility for enterprise-level risk management,while retaining responsibility for oversight of our executive officers in that regard. Our executive officers offer an enterprise-level risk assessment to theBoard at least once every year.Non-Management Executive Sessions and Unitholder CommunicationsNASDAQ listing standards require regular executive sessions of the non-management directors of a listed company, and an executive session forindependent directors at least once a year. At each quarterly Board meeting, all of the directors meet in an executive session. At least annually, ourindependent directors meet in an additional executive session without management participation or participation by non-independent directors.Interested parties can communicate directly with non-management directors by mail in care of Mid-Con Energy Partners, LP, 2431 East 61 Street,Suite 850, Tulsa, Oklahoma 74136. Such communications should specify the intended recipient or recipients. Commercial solicitations or communicationswill not be forwarded.Meetings and Other InformationThe Board of Directors held four quarterly meetings in 2017. Our Partnership Agreement provides that the general partner manages and operates usand that, unlike holders of common stock in a corporation, unitholders only have limited voting rights on matters affecting our business or governance.Accordingly, we do not hold annual meetings of unitholders.Section 16(a) Beneficial Ownership Reporting ComplianceSection 16(a) of the Exchange Act requires executive officers and directors and persons who beneficially own more than 10% of a class of our equitysecurities registered pursuant to Section 12 of the Exchange Act to file certain reports with the SEC and the NASDAQ concerning their beneficial ownershipof such securities. Based solely on a review of the copies of reports on Form 3, Form 4 and From 5 and amendments thereto furnished to us and writtenrepresentations from the executive officers and directors, we believe that all filing requirements applicable to the officers and directors and greater than 10%unitholders were complied with for the fiscal year ended December 31, 2017.Code of EthicsThe governance of Mid-Con Energy GP is, in effect, the governance of our partnership, subject in all cases to any specific unitholder rights containedin our Partnership Agreement.Mid-Con Energy GP has adopted a Code of Business Conduct that applies to all officers, directors and its employees and affiliates. A copy of the Codeof Business Conduct is available on our website at www.midconenergypartners.com. We will provide a copy of the code of ethics to any person, withoutcharge, upon request to Mid-Con Energy Partners, LP, 2431 East 61 Street, Suite 850, Tulsa, Oklahoma 74136, Attn: Investor Relations.Web AccessWe provide access through our website at www.midconenergypartners.com to current information relating to partnership governance, including ourAudit Committee Charter, our Code of Business Conduct and other matters impacting our governance principles. You may access copies of each of thesedocuments from our website. You may also contact the office of the corporate secretary for printed copies of these documents free of charge. Our website andany contents thereof are not incorporated by reference into this document.Communication with DirectorsOur Board believes that it is management’s role to speak for the partnership. Our Board also believes that any communications between members ofthe Board and interested parties, including unitholders, should be conducted with the knowledge of our executive chairman, president and chief executiveofficer. Interested parties, including unitholders, may contact one or more of our Board members, including non-management directors and non-managementdirectors as a group, by writing to the director or directors in care76of the corporate secretary at our principal executive offices. A communication received from an interested party or unitholder will be promptly forwarded tothe director or directors to whom the communication is addressed. A copy of the communication will also be provided to our executive chairman and chiefexecutive officer. We will not, however, forward sales or marketing materials or correspondence primarily commercial in nature, materials that are abusive,threatening or otherwise inappropriate, or correspondence not clearly identified as interested party or unitholder correspondence.ITEM 11.EXECUTIVE COMPENSATIONCompensation Discussion and AnalysisGeneralWe do not directly employ any of the persons responsible for managing our business. Our general partner’s executive officers manage and operate ourbusiness as part of the services provided by Mid-Con Energy Operating to our general partner under the services agreement. All of our general partner’sexecutive officers and other employees necessary to operate our business are employed and compensated by Mid-Con Energy Operating, subject toreimbursement by our general partner. The compensation for all of our executive officers is indirectly paid by us to the extent provided for in the PartnershipAgreement because we reimburse our general partner for payments it makes to Mid-Con Energy Operating.Compensation Committee ReportThe NASDAQ listing rules do not require a listed limited partnership to establish a compensation committee, and we do not have a compensationcommittee. The Board performs the functions of a compensation committee, and although the Board does not currently appoint a compensation committee, itmay do so in the future. The Board has reviewed and discussed with management the Compensation Discussion and Analysis set forth below.Our “named executive officers” for the year ended December 31, 2017, were: Jeffery R. Olmstead Charles R. “Randy” Olmstead Matthew R. Lewis Charles L. McLawhorn IIIThe foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this Annual Report on Form 10-Kinto any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specificallyincorporate this information by reference, and shall not otherwise be deemed filed under those Acts.Objectives of Our Compensation ProgramOur executive compensation program is intended to align the interests of our management team with those of our unitholders by motivating ourexecutive officers to achieve strong financial and operating results for us, which we believe closely correlate to long-term unitholder value. In addition, ourprogram is designed to achieve the following objectives: •attract, retain and reward talented executive officers by providing total compensation competitive with that of other executive officersemployed by exploration and production companies and publicly traded partnerships of similar size; •provide performance-based compensation that balances rewards for short-term and long-term results and is tied to both individual and ourperformance; and •encourage the long-term commitment of our executive officers to the Partnership’s and our unitholders’ long-term interests.Elements of Our Compensation Program and Why We Pay Each ElementTo accomplish our objectives, we seek to offer a compensation program to our executive officers that, when valued in its entirety, serves to attract,motivate and retain executives with the character and expertise required for our growth and development. Our compensation program is comprised of fourelements: •base salary; •discretionary cash bonus;77 •long-term equity-based compensation; and •benefits.The voting members of our general partner have responsibility and authority for compensation-related decisions for our Chief Executive Officer and,upon consultation and recommendations by our Chief Executive Officer, for our other executive officers. Equity grants pursuant to our Long-Term IncentiveProgram are also administered by the voting members of our general partner and approved by the Board.Our general partner also grants equity-based awards to our executive officers pursuant to a Long-Term Incentive Program described below. Incentivecompensation in respect of services provided to us is not tied in any way to the performance of entities other than our partnership. Specifically, anyperformance metrics are not to be tied in any way to the performance of the Mid-Con Affiliates or any other affiliate of ours.Although we bear an allocated portion of Mid-Con Energy Operating’s costs of providing compensation and benefits to Mid-Con Energy Operatingemployees who serve as the executive officers of our general partner and provide services to us, we have no control over such costs and do not establish ordirect the compensation policies or practices of Mid-Con Energy Operating.Mid-Con Energy Operating does not maintain a defined benefit or pension plan for its executive officers or employees because it believes such plansprimarily reward longevity rather than performance. Mid-Con Energy Operating provides a basic benefits package to all its employees, which includes a401(k) plan, health and basic term life insurance and personal accident and long-term disability coverage. Employees provided to us under the servicesagreement will be entitled to the same basic benefits.Employment AgreementsOur general partner has entered into employment agreements with Charles R. Olmstead, Executive Chairman of the Board and Jeffrey R. Olmstead,President and Chief Executive Officer.The employment agreements provide for a term that commences on August 1 of each year with automatic one-year renewal terms unless either we orthe employee gives written notice of termination at least by February 1 preceding any such August 1. Pursuant to the employment agreements, eachemployee will serve in his respective position with our general partner, as set forth above, and has duties, responsibilities, and authority as the Board ofDirectors of our general partner may specify from time to time, in roles consistent with such positions that are assigned to him.The employment agreements also provide for customary confidentiality, non-solicitation, non-compete and indemnification protections. The non-solicitation provisions prohibit an executive from soliciting persons to leave our employment who are employed by us within six months before or after theexecutive’s termination. This restriction continues during the term of and for twelve months following termination of the executive’s employment, and alsofor twelve months following the termination of the solicited employee’s employment. The non-solicitation provisions also prohibit an executive fromsoliciting our customers during the term of and for twelve months following termination of the executive’s employment. The non-competition provisionsprohibit the executive from competing with us during the term of the executive’s employment and for a period during which severance payments are beingmade to the executive, which by the terms of the agreements may be up to two years after the executive’s separation of employment.Long-Term Incentive ProgramOur Long-Term Incentive Program is intended to promote the interests of the partnership and encourage superior performance by providing equityawards to employees, officers, consultants and directors of our general partner and our other affiliates, including Mid-Con Energy Operating and ME3Oilfield Service. The Long-Term Incentive Program is also intended to enhance the ability of the general partner and our other affiliates, including Mid-ConEnergy Operating and ME3 Oilfield Service, to attract and retain the services of individuals who are essential for the growth and profitability of thepartnership and to encourage them to devote their best efforts to advancing the business of the partnership. The type of awards that may be granted under theLong-Term Incentive Program are unit options, unit appreciation rights, unrestricted units, restricted units, phantom units, distribution equivalent rightsgranted with phantom units and other types of awards. The maximum number of our common units that are currently authorized to be awarded under the Planis 3,514,000 units.The Long-Term Incentive Program is currently administered by the voting members of our general partner, and approved by the Board. Except as setforth in the employment agreements of the executive officers of our general partner, we have no set formula for granting awards to our employees, officers,consultants and directors of our general partner and our other affiliates, including Mid-Con Energy Operating and ME3 Oilfield Service. In determiningwhether to grant awards and the amount of any awards, the voting members of the general partner take into consideration the performance of the Partnershipalong with discretionary factors such as the individual’s current and expected future performance, level of responsibility, retention considerations and thetotal compensation package.78Equity Compensation Plan Information as of February 28, 2018: Plan category Number of securities remaining availablefor future issuance under equitycompensation plans Equity compensation plans approved by securityholders 1,427,369 (1)Equity compensation plans not approved bysecurity holders — Total 1,427,369 (1)Represents common units.The plan administrator may terminate or amend the Long-Term Incentive Program at any time with respect to any units for which a grant has not yetbeen made. The plan administrator also has the right to alter or amend the Long-Term Incentive Program or any part of the Long-Term Incentive Programfrom time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common unitsare listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participantwithout the consent of the participant. The Long-Term Incentive Program will expire on the earliest to occur of (i) the date on which all common unitsavailable under the Plan for grants have been paid to participants, (ii) termination of the Plan by the plan administrator or (iii) December 20, 2021.Upon a “change of control” (as defined in the Long-Term Incentive Program), any change in applicable law or regulation affecting the Long-TermIncentive Program or awards thereunder, or any change in accounting principles affecting the financial statements of our general partner, the planadministrator, in an attempt to prevent dilution or enlargement of any benefits available under the Long-Term Incentive Program may, in its discretion,provide that awards will (i) become exercisable or payable, as applicable, (ii) be exchanged for cash, (iii) be replaced with other rights or property selected bythe plan administrator, (iv) be assumed by the successor or survivor entity or be exchanged for similar options, rights or awards covering the equity of suchsuccessor or survivor, or a parent or subsidiary thereof, with other appropriate adjustments or (v) be terminated. Additionally, the plan administrator may also,in its discretion, make adjustments to the terms and conditions, vesting and performance criteria and the number and type of common units, other securities orproperty subject to outstanding awards.The consequences of the termination of a grantee’s employment, consulting arrangement or membership on the Board of Directors will be determinedby the plan administrator in the terms of the relevant award agreement or employment agreement.Common units to be delivered pursuant to awards under the Long-Term Incentive Program may be common units already owned by our generalpartner or us or acquired by our general partner in the open market from any other person, directly from us or any combination of the foregoing. If we issuenew common units upon the grant, vesting or payment of awards under the Long-Term Incentive Program, the total number of common units outstanding willincrease, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awardssettled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.Short-Term Incentive PaymentsShort-term incentive payments are provided to executive officers to recognize and reward their overall performance as determined by the Board. Wedo not provide perquisites to the named executive officers, other than one-time relocation expenses that were provided to Mr. Lewis in 2016.79Summary Compensation TableThe following table sets forth certain information with respect to compensation of our named executive officers for services rendered in all capacitiesto us and our subsidiaries for the years ended December 31, 2017, and 2016. All of these employees are paid by Mid-Con Energy Operating. We reimburseMid-Con Energy Operating for a portion of their compensation according to the services agreement entered between us and Mid-Con Energy Operating. Name and Principal Position Year Salary Bonus Unit Awards All OtherCompensation Total (in thousands) Jeffrey R. Olmstead 2017 $250 $— $— $7 (3) $257 President, CEO and Director 2016 $252 $70 $92 $10 (3) $424 Charles R. Olmstead 2017 $207 $— $— $6 (3) $213 Executive Chairman of the Board 2016 $117 $70 $92 $6 (3) $285 Matthew R. Lewis (1) 2017 $157 $— $— $5 (3) $162 VP, Chief Financial Officer 2016 $162 $41 $37 $30 (4) $270 Charles L. McLawhorn III (2) 2017 $140 $— $— $4 (3) $144 VP, General Counsel and Secretary 2016 $109 $43 $55 $3 (3) $210 (1) Mr. Lewis became Chief Financial Officer during 2016. Mr. Lewis resigned from his position effective November 6, 2017, and served in an advisory role until November 30, 2017.(2) Mr. McLawhorn became General Counsel and Corporate Secretary during 2016.(3) Includes Registrant’s contributions to a defined contribution plan.(4) Includes approximately $6,000 in Registrant’s contributions to a defined contribution plan and approximately $24,000 in relocation expenses.Outstanding Equity Awards at Fiscal Year EndThe following table sets forth certain information with respect to outstanding equity awards at December 31, 2017: Name Number of Units That HaveNot Yet Vested Market Value of UnitsThat Have Not YetVested (1) Jeffrey R. Olmstead 16,666 (2) $19,666 Charles R. Olmstead 16,666 (2) $19,666 Charles L. McLawhorn III 10,000 (2) $11,800 (1)Based on the closing price of our common units at December 31, 2017.(2) These restricted units vest equally over three years beginning July 31, 2016. 80Potential Post-Employment Payments and Payments upon a Change in ControlThe below table summarized the material terms of the employee agreements that provide for payments to named executives in connection with theresignation, retirement or other termination of a named executive officer or a change in control: Term Without Cause or Good ReasonDeath or DisabilityChange in ControlAccrued amounts (1)Amounts earned during employmentAmounts earned duringemploymentAmounts earned during employmentBase Salaryone yearone yeartwo yearsBonus (2)Lesser of: “target annual bonus”, oraverage of previous two annual bonuses“target annual bonus”Twice the lesser of: “target annualbonus”, or average of previous twoannual bonusesHealth-care coverage (3)Amount of CobraAmount of CobraAmount of CobraEquity awardsAccelerated vestingAccelerated vestingAccelerated vesting(1) Includes salary, vacation, benefits and unreimbursed business expenses.(2) “Target annual bonus” as defined in the employment agreement.(3) Lump sum for officer and dependents, if applicable. For the purposes of these agreements, “cause” means the willful and continued failure of the officer to perform substantially the officer’s duties for us(other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to theofficer by the CEO which specifically identifies the manner in which the CEO believes that the officer has not substantially performed the officer’s duties andthe officer is given a reasonable opportunity of not more than twenty business days to cure any such failure to substantially perform; the willful engaging bythe officer in illegal conduct or gross misconduct, including, without limitation, a material breach of the our Code of Business Conduct or a material breachof the officer’s covenants to follow all laws and all of our policies that relate to nondiscrimination and the absence of harassment and to comply with allrequirements under the Sarbanes-Oxley Act, in each case which is materially and demonstrably injurious to us; or any act of fraud, or material embezzlementor material theft by the officer, in each case, in connection with the officer’s duties hereunder or in the course of the officer’s employment hereunder or theofficer’s admission in any court, or conviction, or plea of nolo contendere, of a felony involving moral turpitude, fraud, or material embezzlement, materialtheft or material misrepresentation, in each case, against or affecting us. The CEO’s determination of materiality of any embezzlement, theft, ormisrepresentation, shall be binding and conclusive on the officer.For the purposes of these agreements, “good reason” means the occurrence of any of the following without the officers written consent: a materialdiminution in the officer’s base salary; a material diminution in the officer’s authority, duties, or responsibilities; a material diminution in the budget overwhich the officer retains authority; a material change (more than 25 miles) in the geographic location at which the officer’s primary location of his under hisemployment agreement; or any other action or inaction that constitutes a material breach by us of the employment agreement.Potential Post-Employment Payment Tables - The following tables reflect estimates of our allocated portion of the amount of incrementalcompensation due to each named executive officer subject to an employment agreement in the event of such executive’s termination of employment upondeath, disability or retirement, termination of employment without cause or termination of employment without cause or with good reason within three yearsfollowing a change in control. The amounts shown assume that such termination was effective as of December 31, 2017, and are estimates of the allocatedamounts which would be paid out to the executives upon such termination. The actual amounts to be paid out can only be determined at the time of suchexecutive’s separation of service. Charles R. Olmstead Termination UponDeath, Disabilityor Retirement TerminationWithout Cause QualifyingTerminationFollowingChange in Control Cash Severance $212,400 $212,400 $424,800 Restricted Stock/Units 19,666 19,666 19,666 Performance Shares/Units 59,000 59,000 59,000 Health & Welfare 36,360 36,360 36,360 Total $327,426 $327,426 $539,826 81Jeffrey R. Olmstead Termination UponDeath, Disabilityor Retirement TerminationWithout Cause QualifyingTerminationFollowingChange in Control Cash Severance $247,800 $247,800 $495,600 Restricted Stock/Units 19,666 19,666 19,666 Performance Shares/Units 59,000 59,000 59,000 Health & Welfare 53,784 53,784 53,784 Total $380,250 $380,250 $628,050Relation of Compensation Policies and Practices to Risk ManagementOur compensation policies and practices are designed to provide rewards for short-term and long-term performance, both on an individual basis and atthe entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk taking.Accordingly, the use of compensation as an incentive for performance can foster the potential for management and others to take unnecessary or excessiverisks to reach performance thresholds which qualify them for additional compensation. From a risk management perspective, our policy is to conduct ourcommercial activities in a manner intended to control and minimize the potential for unwarranted risk taking. We also routinely monitor and measure theexecution and performance of our projects and acquisitions relative to expectations. Additionally, our compensation arrangements include delaying therewards and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices or of our code ofconduct.Compensation Committee Interlocks and Insider ParticipationThe NASDAQ listing rules do not require a listed limited partnership to establish a compensation committee, and we do not have a compensationcommittee. Although the Board does not currently establish a compensation committee, it may do so in the future.Compensation of DirectorsWe use a combination of cash and unit-based compensation to attract and retain qualified candidates to serve on our Board. In setting directorcompensation, we consider the significant amount of time that directors expend in fulfilling their duties to us as well as the skill level we require of membersof the Board.In 2017, directors who were not officers or employees received an annual retainer of $20,000, with the chairman of the audit committee and chairmanof the conflict committee receiving an additional annual fee of $5,000. In addition, each non-employee director receives $1,000 per meeting attended inperson or by phone and is reimbursed for his out of pocket expenses in connection with attending meetings. We indemnify each director for his actionsassociated with being a director to the fullest extent permitted under Delaware law.Each of the non-management directors were awarded 4,000 unrestricted common units in February 2017.The following table discloses the cash, unit awards and other compensation earned, paid or awarded to each of our directors during the year endedDecember 31, 2017: Name (1) Fee Earned orPaid in Cash Unit Awards (2) Total Peter Adamson III $33,000 $10,600 $43,600 C. Fred Ball Jr. $28,000 $10,600 $38,600 John W. Brown(3) $21,000 $— $21,000 Wilkie Colyer $24,000 $10,600 $34,600 Peter A. Leidel $24,000 $10,600 $34,600 Cameron O. Smith $32,000 $10,600 $42,600(1 ) Messrs. Olmstead and Olmstead and not included in this table as they are employees of Mid-Con Energy Operating and receive no compensation for their servicesas directors.(2) Reflects the fair value of the units granted in February 2017.(3) Mr. Brown was elected to the Board in April 2017. 82ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ANDRELATED STOCKHOLDER MATTERSAs of February 28, 2018, the following table sets forth the beneficial ownership of our voting securities that are owned by: •beneficial owners of more than 5% of our common units; •each of the directors and Named Executive Officers of our general partner; and •all directors, director nominees and executive officers of our general partner as a group. Name of Beneficial Owner Common UnitsBeneficiallyOwned (1) Percentage ofCommon UnitsBeneficially Owned Class APreferred UnitsBeneficiallyOwned (2) Percentage ofClass APreferred UnitsBeneficially Owned Class BPreferred UnitsBeneficiallyOwned (2) Percentage ofClass B PreferredUnitsBeneficially Owned Mid-Con Energy III, LLC(3) 3,714,659 12.2% 930,223 8.0% 522,875 5.3%John C. Goff(4) — —% 4,790,697 41.2% 9,281,046 94.7%James M. Howard(4) — —% 1,860,465 16.0% 1,568,628 16.0%Robert W. Stallings(5) — —% 1,860,465 16.0% — —% James R. Reis(5)(6) — —% 1,627,907 14.0% — —% Bonanza Master Fund, Ltd.(7) — —% 930,233 8.0% — —% Robert J. Raymond(8) 2,358,225 7.7% 232,558 2.0% — —% Charles R. Olmstead(9) 757,512 2.5% — —% — —% Jeffrey R. Olmstead(9) 475,763 1.6% — —% — —% Charles L. McLawhorn III(9) 16,020 * — —% — —% Sherry L. Morgan(9) 26,477 * — —% — —% Peter Adamson III(9) 82,685 * — —% — —% C. Fred Ball Jr.(9) 91,310 * — —% — —% Peter A. Leidel(9) 275,305 * — —% — —% Cameron O. Smith(9) 47,340 * — —% — —% Wilkie S. Colyer Jr.(9) 4,000 * — —% — —% Matthew R. Lewis(9)(10) 27,706 * — —% — —% All named executive officers, directors anddirector nominees as a group (10 people) 1,804,118 5.9% — —% — —%* Represents less than 1.0% of the outstanding class of voting securities.(1) Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act. Under this rule, a person is generally considered to be the beneficial owner ofa security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers with sixtydays.(2) In August 2016, we issued 11,627,906 Class A Preferred Units. In January 2018, we issued 9,803,921 Class B Preferred Units. Holders of our Preferred Units may elect to convertinto common units representing limited partner interests in our partnership on a one-for-one basis at any time after the six-month anniversary of the applicable closing date, in wholeor in part, subject to certain conversion thresholds.(3) C/o Mid-Con Energy GP, LLC, 2431 E. 61st Street, Suite 850, Tulsa, Oklahoma 74136.(4) This disclosure is based on the Schedule 13D filed with the SEC on January 31,2018, on behalf of each of the following: (i) John C. Goff; (ii) Goff REN Holdings, LLC (“GoffREN”); (iii) Goff MCEP Holdings, LLC (“Goff MCEP Holdings”); (iv) The Goff Family Foundation (“Goff Foundation”); (v) Goff Capital, Inc. (“Goff Capital”); (vi) GFS REN GP,LLC (“GFS REN”); (vii) GFS Management, LLC (“GFS”); (viii) Goff Focused Strategies, LLC (“Goff Focused”); (ix) Longboat Capital, LLC (“Longboat Capital”); and (x) JamesM. Howard. As of the date of such filing, John C. Goff may be deemed the beneficial owner of (1) 1,860,465 Class A Preferred Units and 784,314 Class B Preferred Units owned byGoff REN, (2) 2,697,674 Class A Preferred Units owned by Goff MCEP Holdings, (3) 232,558 Class A Preferred Units owned by Goff Foundation, (4) 784,314 Class B PreferredUnits owned by GFS REN, (5) 5,098,039 Class B Preferred Units owned by GFS and (6) 2,614,379 Class B Preferred Units owned by Goff Focused. As the manager of Goff MCEPHoldings and a member of Goff REN, Goff Capital may be deemed to have the sole power to vote or direct the vote of and the sole power to dispose or direct the disposition of thePreferred Units of Goff MCEP Holdings and the shared power to vote or direct the vote of and the shared power to dispose or direct the disposition of the Preferred Units of GoffREN. Goff Capital disclaims beneficial ownership of the Preferred Units of Goff MCEP Holdings and the Preferred Units of Goff REN, except to the extent of its pecuniary interesttherein. As the sole board member of Goff Foundation and as president of Goff Capital, John C. Goff may be deemed to have the sole power to vote or direct the vote of and thesole power to dispose or direct the disposition of the Preferred Units of Goff Foundation and the Preferred Units of Goff MCEP Holdings and the shared power to vote or direct thevote of and the shared power to dispose or direct the disposition of the Preferred Units of Goff REN (which are also reported as Preferred Units beneficially owned by Mr. Howardin the table above). Mr. Goff disclaims beneficial ownership of all of the Preferred Units, except to the extent of its pecuniary interest therein. As a member of Goff REN, LongboatCapital may be deemed to have the shared power to vote or direct the vote of and the shared power to dispose or direct the disposition of the Preferred Units of Goff REN. LongboatCapital disclaims beneficial ownership of those Preferred Units, except to the extent of its pecuniary interest therein. As the co-manager of Goff REN, and as manager of LongboatCapital, James M. Howard may be deemed to have the shared power to vote or direct the vote of and the shared power to dispose or direct the disposition of the Preferred Units ofGoff REN (which are also reported as Preferred Units beneficially owned by Mr. Goff in the table above). Mr. Howard disclaims beneficial ownership of those Preferred Units,except to the extent of its pecuniary interest therein. Mr. Goff has a principal business address of 500 Commerce Street, Suite 700, Fort Worth, Texas 76102.(5) This disclosure is based on the Schedule 13D filed with the SEC on December 14, 2016 on behalf of each of the following: (i) GAINSCO, Inc. (“GAINSCO”); (ii) SCG Ventures LP(“SCG Ventures”); (iii) FWC Holdings, LLC (“FWC Holdings”); (iv) Stallings Management, LLC (“Stallings Management”); (v) Robert W. Stallings; and (vi) James R. Reis. As ofthe date of such filing, Mr. Stallings may be deemed the beneficial owner of (1) 1,395,349 Class A Preferred Units owned by GAINSCO (which are also reported as Class APreferred Units beneficially owned by Mr. Reis in the table above), and (2) 465,116 Class A Preferred Units owned by Stallings Management. As President of Stallings Managementand Chairman of the Board of GAINSCO, Robert W. Stallings may be deemed to have the sole power to vote or direct the vote of and the sole power to dispose or direct thedisposition of the Class A Preferred Units of SCG Ventures and the common units into which such Class A Preferred Units are convertible and the shared power to vote or direct thevote of and the shared power to dispose or direct the disposition of such securities of83GAINSCO. Mr. Stallings disclaims beneficial ownership of all of the Class A Preferred Units and the common units into which the Class A Preferred Units are convertible, except tothe extent of his pecuniary interest therein. As the general partner of SCG Ventures, Stallings Management may be deemed to have the sole power to vote or direct the vote of andthe sole power to dispose or direct the disposition of the Class A Preferred Units of SCG Ventures and the common units into which the Class A Preferred Units are convertible.Stallings Management disclaims beneficial ownership of those securities, except to the extent of its pecuniary interest therein. Mr. Stallings has a principal business address of 3333Lee Parkway, Suite 1200, Dallas, Texas 75219.(6) This disclosure is based on the Schedule 13D filed with the SEC on December 14, 2016. As the sole member of FWC Holdings and the Vice Chairman of the Board of GAINSCO,Mr. James R. Reis may be deemed to have the sole power to vote or direct the vote of and the sole power to dispose or direct the disposition of the Preferred Units of FWC Holdings(232,558 Class A Preferred Units) and the common units into which such Class A Preferred Units are convertible and the shared power to vote or direct the vote of and the sharedpower to dispose or direct the disposition of such securities of GAINSCO (1,395,349 Class A Preferred Units, which are also reported as Class A Preferred Units beneficially ownedby Mr. Stallings in the table above). Mr. Reis disclaims beneficial ownership of all of the Class A Preferred Units and the common units into which the Class A Preferred Units areconvertible, except to the extent of his pecuniary interest therein. Mr. Reis has a principal business address of 3333 Lee Parkway, Suite 1200, Dallas, Texas 75219.(7) Has a principal business address of 2651 North Harwood Suite 530, Dallas, Texas 75201.(8) This disclosure is based on the Schedule 13G filed with the SEC on December 31, 2017. As the sole member of RR Advisors, LLC, RCH Black Fund GP, LP, and RCH Black Fund,LP, Mr. Robert J. Raymond may be deemed to have the sole power to vote or direct the vote of and the sole power to dispose or direct the disposition of the Preferred Units of RRAdvisors, LLC, (232,558 Class A Preferred Units) and the common units into which such Class A Preferred Units are convertible and the shared power to vote or direct the vote ofand the shared power to dispose or direct the disposition of such securities of RCH Black Fund GP, LP, and RCH Black Fund LP. Mr. Reis disclaims beneficial ownership of all of theClass A Preferred Units and the common units into which the Class A Preferred Units are convertible, except to the extent of his pecuniary interest therein. Mr. Raymond has aprincipal business address of 3953 Maple Avenue, Suite 180, Dallas, Texas 75219.(9) Has a principal business address of 2431 E. 61st Street, Suite 850, Tulsa, Oklahoma 74136.(10) Mr. Lewis resigned his position of Vice President and Chief Financial Officer effective November 6, 2017. The following table sets forth the beneficial ownership of equity interests in our general partner: Name of Beneficial Owner Class A MembershipInterests Class B MembershipInterests (3) TotalMembershipInterests (4) Charles R. Olmstead (1) 50.00% —% 33.33%Jeffrey R. Olmstead (1) 50.00% —% 33.33%S. Craig George (2) —% 100.00% 33.33% (1)C/o Mid-Con Energy GP, LLC, 2431 E. 61st Street, Suite 850, Tulsa, Oklahoma, 74136. (2)Has a principal address of 340 Barnside Lane, Eureka, Missouri, 63025. (3)On January 24, 2017, the members of the general partner, executed the Second Amendment and Restated Limited Liability Company Agreement of Mid-ConEnergy GP, LLC (the “Second A/R LLC Agreement”). The Second A/R LLC Agreement was effective January 24, 2017 and created a new class of non-votingmembership interests, entitled Class B Membership Interests. Concurrent with his resignation from the Board of Directors of the general partner, Mr. Georgeconverted all of his membership interests of the general partner into the new Class B Membership Interests. (4)Messrs. Olmstead, Olmstead and George, by virtue of their ownership interest in our general partner, may be deemed to beneficially own the interests in us heldby our general partner. Each of Messrs. Olmstead, Olmstead and George disclaims beneficial ownership of these securities in excess of his pecuniary interest insuch securities.Securities Authorized for Issuance under Equity Compensation PlanSee the table in Item 11. “Executive Compensation - Long-Term Incentive Program.”ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCEAs of December 31, 2017, our general partner has an approximate 1.2% interest in us. The distributions we will make to our general partner aredescribed in Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issue Purchases of Equity Securities.”Agreements and Transactions with AffiliatesThe following agreements were negotiated among affiliated parties and, consequently, are not the result of arm’s length negotiations. The following isa description of those agreements that have been entered into with the affiliates of our general partner and with our general partner.Services AgreementWe are party to a services agreement with our affiliate, Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provides certainservices to us, including management, administrative and operational services. The operational services include marketing, geological and engineeringservices. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performanceunder the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons whoperform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. These expenses are included in general andadministrative expenses in our consolidated statements of operations. For the year ended December 31, 2017, we paid Mid-Con Energy Operatingapproximately $2.4 million for expenses pursuant to the services agreement.84Operating AgreementsWe, various third parties with an ownership interest in the same property and our affiliate, Mid-Con Energy Operating, are parties to standard oil andnatural gas joint operating agreements, pursuant to which we and those third parties pay Mid-Con Energy Operating overhead associated with operating ourproperties. We and those third parties also pay Mid-Con Energy Operating for its direct and indirect expenses that are chargeable to the wells under theirrespective operating agreements. The majority of these expenses are included in lease operating expenses in our consolidated statements of operations. Forthe year ended December 31, 2017, we paid Mid-Con Energy Operating approximately $6.5 million for expenses incurred pursuant to the operatingagreements.Oilfield ServicesAs discussed above, we are party to operating agreements, pursuant to which our affiliate, Mid-Con Energy Operating, bills us for direct and indirectexpenses that are chargeable to the wells, including oilfield services performed by our affiliates, ME3 Oilfield Service and ME2 Well Services. Theseamounts are included either in lease operating expenses in our consolidated statements of operations or are capitalized as part of oil and natural gasproperties in our consolidated balance sheets. For the year ended December 31, 2017, we paid Mid-Con Energy Operating approximately $3.4 million foroilfield services performed by ME3 Oilfield Service and ME3 Well Services.Review, Approval or Ratification of Transactions with Related PersonsWe have adopted a Code of Business Conduct that sets forth our policies for the review, approval and ratification of transactions with related persons.Pursuant to our Code of Business Conduct, a director is expected to bring to the attention of the Chief Executive Officer or the Board of Directors of ourgeneral partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or ourgeneral partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with our general partner’sorganizational documents and the provisions of our Partnership Agreement. The resolution may be determined by disinterested directors, our generalpartner’s Board of Directors, or the conflicts committee of our general partner’s Board of Directors. Our Code of Business Conduct is on our websitewww.midconenergypartners.com under our corporate governance section.The Mid-Con Affiliates or other affiliates of our general partner are free to offer properties to us on terms they deem acceptable, and the Board ofDirectors of our general partner (or the conflicts committee) is free to accept or reject any such offers, negotiating terms it deems acceptable to us. As a result,the Board of Directors of our general partner (or the conflicts committee) will decide, in its sole discretion, the appropriate value of any assets offered to us byaffiliates of our general partner. In so doing, we expect the Board of Directors of our general partner (or the conflicts committee) will consider a number offactors in its determination of value, including, without limitation, production and reserve data, operating cost structure, current and projected cash flow,financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, reserve life, future drillinginventory and the weighting of the expected production between oil and natural gas.We expect that the Mid-Con Affiliates or other affiliates of our general partner will consider a number of the same factors considered by the Board ofDirectors of our general partner to determine the proposed purchase price of any assets it may offer to us in future periods. In addition to these factors, giventhat the Charles R. Olmstead, Jeffrey R. Olmstead and Yorktown are significant unitholders, they may consider the potential positive impact on theirunderlying investment in us by causing the Mid-Con Affiliates to offer properties to us at attractive purchase prices. Likewise, the affiliates of our generalpartner may consider the potential negative impact on their underlying investment in us if we are unable to acquire additional assets on favorable terms,including the negotiated purchase price.Director IndependenceNASDAQ does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the Board of Directors ofour general partner. For a discussion of the independence of the Board of Directors of our general partner, please see Item 10. “Directors, Executive Officersand Corporate Governance.”85ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICESThe audit committee of Mid-Con Energy GP, LLC, selected Grant Thornton, LLP, an independent registered public accounting firm, to audit ourconsolidated financial statements for the years ended December 31, 2017 and 2016. The audit committee’s charter requires the audit committee to approve inadvance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below with respect to this Annual Report on Form 10–K for the year ended December 31, 2017, were approved by theaudit committee.Fees paid to Grant Thornton, LLP are as follows: 2017 2016 Audit fees $393,000 $403,000 Audit-related — — Tax fees 131,152 134,911 Total $524,152 $537,911 86PART IVITEM 15.EXHIBITS(a)(1) ExhibitsThe exhibits listed below are filed or furnished as part of this report: ExhibitNumber Description 3.1 Certificate of Limited Partnership of Mid-Con Energy Partners, LP (incorporated by reference to Exhibit 3.1 to Mid-Con EnergyPartners, LP’s registration statement on Form S-1 filed with the SEC on August 12, 2011 (File No.333-176265)). 3.2 Certificate of Formation of Mid-Con Energy GP, LLC (incorporated by reference to Exhibit 3.4 to Mid-Con Energy Partners, LP’sregistration statement on Form S-1 filed with the SEC on August 12, 2011 (File No. 333-176265)). 3.3 First Amended and Restated Agreement of Limited Partnership of Mid-Con Energy Partners, LP, dated as of December 20, 2011(incorporated by reference to Exhibit 3.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC onDecember 23, 2011). 3.4 First Amendment to First Amended and Restated Agreement of Limited Partnership of Mid-Con Energy Partners, LP, dated as ofAugust 11, 2016 (incorporated by reference to Exhibit 3.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with theSEC on August 16, 2016). 3.5 Second Amendment to First Amended and Restated Agreement of Limited Partnership of Mid-Con Energy Partners, LP, dated as ofJanuary 31, 2018 (incorporated by reference to Exhibit 3.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with theSEC on January 31, 2018). 3.6 Amended and Restated Limited Liability Company Agreement of Mid-Con Energy GP, LLC, dated as of December 20, 2011(incorporated by reference to Exhibit 3.2 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC onDecember 23, 2011). 3.7 Second Amended and Restated Limited Liability Company Agreement of Mid-Con Energy GP, LLC (incorporated by reference toExhibit 3.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on January 25, 2017). 10.1 Services Agreement, dated as of December 20, 2011, by and among Mid-Con Energy Operating, Inc., Mid-Con Energy GP, LLC, Mid-Con Energy Partners, LP and Mid-Con Energy Properties, LLC (incorporated by reference to Exhibit 10.1 to Mid-Con EnergyPartners, LP’s current report on Form 8-K filed with the SEC on December 23, 2011). 10.2 Credit Agreement, dated as of December 20, 2011, among Mid-Con Energy Properties, LLC, as Borrower, Royal Bank of Canada, asAdministrative Agent and Collateral Agent and the lenders party thereto (incorporated by reference to Exhibit 10.2 to Mid-ConEnergy Partners, LP’s current report on Form 8-K filed with the SEC on December 23, 2011). 10.3 Agreement and Amendment No. 1 to Credit Agreement, dated as of April 23, 2012, among Mid-Con Energy Properties, LLC, asBorrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated byreference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on April 27, 2012). 10.4 Agreement and Amendment No. 2 to Credit Agreement, dated as of November 26, 2012, among Mid-Con Energy Properties, LLC, asBorrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated byreference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on November 28, 2012). 10.5 Agreement and Amendment No.3 to Credit Agreement, dated as of November 5, 2013, among Mid-Con Energy Properties, LLC, asBorrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated byreference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on November 6, 2013). 10.6 Amendment No.4 to Credit Agreement, dated as of April 11, 2014, among Mid-Con Energy Properties, LLC, as Borrower, Royal Bankof Canada, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated by reference to Exhibit 10.01 toMid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on April 15, 2014).87 10.7 Agreement and Amendment No.5 to Credit Agreement, dated as of November 17, 2014, among Mid-Con Energy Properties, LLC, asBorrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated byreference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on November 18, 2014). 10.8 Amendment No.6 to Credit Agreement, dated as of February 12, 2015, among Mid-Con Energy Properties, LLC, as Borrower, RoyalBank of Canada, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated by reference to Exhibit10.01 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on February 17, 2015). 10.9 Amendment No.7 to Credit Agreement, dated as of November 30, 2015, among Mid-Con Energy Properties, LLC, as Borrower, RoyalBank of Canada, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated by reference to Exhibit10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on December 1, 2015). 10.10 Amendment No.8 to Credit Agreement, dated as of April 29, 2016, among Mid-Con Energy Properties, LLC, as Borrower, Wells FargoBank, National Association, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated by reference toExhibit 10.3 to Mid-Con Energy Partners, LP’s quarterly report on Form 10-Q filed with the SEC on May 2,2016). 10.11 Amendment No.9 to Credit Agreement, dated as of May 31, 2016, among Mid-Con Energy Properties, LLC, as Borrower, Wells FargoBank, National Association, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated by reference toExhibit 10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on June 2, 2016). 10.12 Amendment No.10 to Credit Agreement, dated as of August 11, 2016, among Mid-Con Energy Properties, LLC, as Borrower, WellsFargo Bank, National Association, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated byreference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on August 16, 2016). 10.13 Amendment No.11 to Credit Agreement, dated as of December 22, 2017, among Mid-Con Energy Properties, LLC, as Borrower, WellsFargo Bank, National Association, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated byreference to Exhibit 10.2 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on December 29, 2017). 10.14 Amendment No.12 to Credit Agreement, dated as of January 31, 2018, among Mid-Con Energy Properties, LLC, as Borrower, WellsFargo Bank, National Association, as Administrative Agent and Collateral Agent and the lenders party thereto (incorporated byreference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on January 31, 2018). 10.15 Contribution, Conveyance, Assumption and Merger Agreement, by and among Mid-Con Energy GP, LLC, Mid-Con Energy Partners,LP, Mid-Con Energy Properties, LLC, Mid-Con Energy I, LLC, Mid-Con Energy II, LLC, and Charles R. Olmstead, S. Craig George,Jeffrey R. Olmstead and other members of Mid-Con Energy I, LLC, and Mid-Con Energy II, LLC, named therein (incorporated byreference to Exhibit 10.3 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on December 23, 2011). 10.16 Mid-Con Energy Partners, LP Long-Term Incentive Program (incorporated by reference to Exhibit 4.5 to Mid-Con Energy Partners,LP’s Registration Statement on Form S-8 filed with the SEC on January 25, 2012 (File No 333-179161)). 10.17 Amendment No. 1 to Mid-Con Energy Partners, LP Long-Term Incentive Program (incorporated by reference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on November 20, 2015). 10.18 Form of Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.5 to Mid-Con Energy Partners, LP’s current reporton Form 8-K filed with the SEC on December 23, 2011). 10.19 Form of Phantom Unit Award Agreement (for employees of our Affiliate)(incorporated by reference to Exhibit 10.14 to Mid-ConEnergy LP’s current report on Form 10-K/A filed with the SEC on June 24, 2014). 10.20 Class A Convertible Preferred Unit Purchase Agreement, dated as of July 31, 2016, by and among Mid-Con Energy Partners, LP andthe Purchasers named on Schedule A thereto (incorporated by reference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s currentreport on Form 8-K file with the SEC on August 3, 2016). 8810.21 Class B Convertible Preferred Unit Purchase Agreement, dated January 23, 2018, by and among Mid-Con Energy Partners, LP and thePurchasers named on Schedule A thereto (incorporated by reference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s current reporton Form 8-K file with the SEC on January 29, 2018). 10.22 Employment Agreement, dated as of August 1, 2011, by and among Mid-Con Energy Partners, LP, Mid-Con Energy GP, LLC, andCharles R. Olmstead (incorporated by reference to Exhibit 10.6 to Mid-Con Energy Partners, LP’s current report on Form 8-K filedwith the SEC on December 23, 2011). 10.23 Employment Agreement, dated as of August 1, 2011, by and among Mid-Con Energy Partners, LP, Mid-Con Energy GP, LLC, andJeffrey R. Olmstead (incorporated by reference to Exhibit 10.7 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed withthe SEC on December 23, 2011). 10.24 Purchase and Sale Agreement dated as of May 26, 2016, among Mid-Con Energy Properties, LLC, Mid-Con Energy Operating, LLC,as sellers, and PO&G Panhandle, LP, as purchaser thereto (incorporated by reference to Exhibit 10.7 to Mid-Con Energy Partners, LP’squarterly report on Form 10-Q filed with the SEC on August 4, 2016). 10.25 Purchase and Sale Agreement, dated as of July 28, 2016, among Mid-Con Energy Properties, LLC, as purchaser, and WalterExploration Company, JMW LTD, and Wildcat Properties L.P., as sellers thereto (incorporated by reference to Exhibit 10.8 to Mid-Con Energy Partners, LP’s quarterly report on Form 10-Q filed with the SEC on August 4, 2016). 10.26 Purchase and Sale Agreement, dated as of November 8, 2017, among Mid-Con Energy Properties, LLC, as seller, and ExponentEnergy III LLC, as purchaser thereto (incorporated by reference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s quarterly report onForm 10-Q filed with the SEC on November 14, 2017). 10.27 Amendment to Purchase and Sale Agreement, dated December 22, 2017, among Mid-Con Energy Properties, LLC, as seller, andExponent Energy III LLC, as purchaser thereto (incorporated by reference to Exhibit 10.1 to Mid-Con Energy Partners, LP’s currentreport on Form 8-K filed with the SEC on December 29, 2017). 21.1 Subsidiaries of Mid-Con Energy Partners, LP (incorporated by reference to Exhibit 21.1 to Mid-Con Energy LP’s current report onForm 10-K filed with the SEC on March 9, 2012). 23.1+ Consent of Cawley, Gillespie & Associates, Inc. 23.2+ Consent of Grant Thornton LLP 31.1+ Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer 31.2+ Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer 32.1+ Section 1350 Certification of Chief Executive Officer 32.2+ Section 1350 Certification of Principal Financial Officer 99.1+ Cawley, Gillespie & Associates, Inc. Reserve Report 101.INS++ XBRL Instance Document 101.SCH++ XBRL Taxonomy Extension Schema Document 101.CAL++ XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF++ XBRL Taxonomy Extension Definition Linkbase Document 101.LAB++ XBRL Taxonomy Extension Label Linkbase Document 101.PRE++ XBRL Taxonomy Extension Presentation Linkbase Document Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC uponrequest. +Filed herewith++Furnished herewith 89SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed onits behalf by the undersigned thereunto duly authorized. Mid-Con Energy Partners, LP(Registrant) By: Mid-Con Energy GP, LLC, its general partnerDate: February 28, 2018By: /s/ Sherry L. Morgan Sherry L. MorganChief Accounting Officeras Principal Financial OfficerPursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of theregistrant and in the capacities indicated on February 28, 2018. Signature TitleDate /s/ Jeffrey R. Olmstead Chief Executive Officer and DirectorFebruary 28, 2018Jeffrey R. Olmstead (Principal Executive Officer) /s/ Sherry L. Morgan Chief Accounting OfficerFebruary 28, 2018Sherry L. Morgan (As Principal Financial Officer) /s/ Charles R. Olmstead Executive Chairman of the BoardFebruary 28, 2018Charles R. Olmstead /s/ Peter Adamson III DirectorFebruary 28, 2018Peter Adamson III /s/ C. Fred Ball Jr. DirectorFebruary 28, 2018C. Fred Ball Jr. /s/ John W. Brown DirectorFebruary 28, 2018John W. Brown /s/ Wilkie S. Colyer Jr. DirectorFebruary 28, 2018Wilkie S. Colyer Jr. /s/ Peter A. Leidel DirectorFebruary 28, 2018Peter A. Leidel /s/ Cameron O. Smith DirectorFebruary 28, 2018Cameron O. Smith 90Exhibit 23.1CAWLEY, GILLESPIE & ASSOCIATES, INC.PETROLEUM CONSULTANTS13640 BRIARWICK DRIVE, SUITE 100306 WEST SEVENTH STREET, SUITE 3021000 LOUISIANA STREET, SUITE 1900AUSTIN, TEXAS 78729-1707FORT WORTH, TEXAS 76102-4987HOUSTON, TEXAS 77002-5008512-249-7000817- 336-2461713-651-9944www.cgaus.com CONSENT OF INDEPENDENT PETROLEUM ENGINEERS We hereby consent to the references to our firm, references to Cawley, Gillespie & Associates, Inc. as independent petroleumengineers and to the inclusion of information taken from our reserve audit of Mid-Con Energy Partners, LP as of December 31, 2017in the Mid-Con Energy Partners, LP Annual Report on Form 10-K for the year ended December 31, 2017, (the “10-K”) and allappendixes, exhibits and attachments thereto filed by Mid-Con Energy Partners, LP. We further consent to the inclusion of our reserveaudit dated January 22, 2018 as Exhibit 99.1 in the 10-K. Sincerely, W. Todd Brooker, President Texas Registered Engineering Firm F-693 February 21, 2018 Fort Worth, Texas Exhibit 23.2CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We have issued our report dated February 28, 2018, with respect to the consolidated financial statements included in the Annual Report of Mid-ConEnergy Partners, LP on Form 10-K for the year ended December 31, 2017. We consent to the incorporation by reference of said report in the RegistrationStatements of Mid-Con Energy Partners, LP on Forms S-3 (File No. 333-214536, File No. 333-195669 and File No. 333-187012) and on Forms S-8 (File No.333-179161 and File No. 333-208203)./s/ GRANT THORNTON LLP Tulsa, OklahomaFebruary 28, 2018 Exhibit 31.1CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TOEXCHANGE ACT RULE 13a-14(a)/15d-14(a)AS ADOPTED PURSUANT TO SECTION 302OF THE SARBANES-OXLEY ACT OF 2002I, Jeffrey R. Olmstead, certify that: 1.I have reviewed this Annual Report on Form 10-K of Mid-Con Energy Partners, LP; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting. Date:February 28, 2018/s/ Jeffrey R. Olmstead Jeffrey R. OlmsteadChief Executive Officer Exhibit 31.2CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TOEXCHANGE ACT RULE 13a-14(a)/15d-14(a)AS ADOPTED PURSUANT TO SECTION 302OF THE SARBANES-OXLEY ACT OF 2002I, Sherry L. Morgan, certify that: 1.I have reviewed this Annual Report on Form 10-K of Mid-Con Energy Partners, LP;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; (c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting. Date:February 28, 2018 Sherry L. MorganChief Accounting Officeras Principal Financial Officer Exhibit 32.1CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TO SECTION 906OF THE SARBANES-OXLEY ACT OF 2002In connection with the Annual Report of Mid-Con Energy Partners, LP (the “Partnership”) on Form 10-K for the year ended December 31, 2017, as filed withthe Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey R. Olmstead, Chief Executive Officer of the Partnership, certify,pursuant to 18 U.S.C § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: 1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of theCompany. Date:February 28, 2018/s/ Jeffrey R. Olmstead Jeffrey R. OlmsteadChief Executive Officer Exhibit 32.2CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TO SECTION 906OF THE SARBANES-OXLEY ACT OF 2002In connection with the Annual Report of Mid-Con Energy Partners, LP (the “Partnership”) on Form 10-K for the year ended December 31, 2017, as filed withthe Securities and Exchange Commission on the date hereof (the “Report”), I, Sherry L. Morgan, as Principal Financial Officer of the Partnership, certify,pursuant to 18 U.S.C § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: 1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of theCompany. Date:February 28, 2018/s/ Sherry L. Morgan Sherry L. MorganChief Accounting Officeras Principal Financial Officer  Exhibit 99.1CAWLEY, GILLESPIE & ASSOCIATES, INC.petroleum consultants13640 BRIARWICK DRIVE, SUITE 100306 WEST SEVENTH STREET, SUITE 3021000 LOUISIANA STREET, SUITE 1900AUSTIN, TEXAS 78729-1707FORT WORTH, TEXAS 76102-4987HOUSTON, TEXAS 77002-5008512-249-7000817- 336-2461713-651-9944www.cgaus.com January 22, 2018 Mr. Jeffrey R. OlmsteadChief Executive OfficerMid-Con Energy Partners, LP2431 E. 61st Street, Suite 850Tulsa, OK 74136 Re:ReserveAuditMid-Con Energy Partners, LP InterestsTotal Proved ReservesAs of December 31, 2017 Pursuant to the Guidelines of theSecurities and Exchange Commission forReporting Corporate Reserves andFuture NetRevenue Dear Mr. Olmstead, At your request, this letter was prepared for Mid-Con Energy Partners, LP (“MCEP”) on January 22, 2018 for the purpose ofdescribing our audit of your estimates of proved reserves and forecasts of economics attributable to the subject interests. We examined100% of MCEP reserves, which are made up of oil and gas properties in various fields in Texas and Oklahoma. This examinationutilized an effective date of December 31, 2017, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) ofRegulation S-K and other rules of the Securities and Exchange Commission (SEC). Our examination included all methods andprocedures as we considered necessary under the circumstances to render the opinion set forth herein. The estimates as prepared byMCEP are summarized as follows: Cumulative NetNet Cash Flow OilGasNetDisc. @ 10% (Mbbls)(MMcf)MBOE(M$) Total Proved18,5106,28219,557212,025 Proved Developed Producing11,9864,25312,695139,207 Proved Developed Behind Pipe480744937,793 Proved Developed Non-Producing1,0452591,08817,017 Proved Undeveloped4,9981,6965,28148,008 Mid-Con Energy Partners, LPReserve AuditJanuary 22, 2018Page 2 Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costsand operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flowhas been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effectof time on the value of money and should not be construed as being the fair market value of the properties.The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standardcubic feet (Mcf) at contract temperature and pressure base. Our audit involved proved reserves only and did not include any probableor possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves havebeen estimated. 0BHydrocarbon PricingThe base SEC oil and gas prices calculated for December 31, 2017 were $51.34/bbl and $2.98/MMBTU, respectively. Asspecified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil and gas prices arebased upon WTI-Cushing and Henry Hub spot prices, respectively, as published by the EIA for January 1, 2017 through December 1,2017. The base prices shown above were adjusted for differentials on a per-property basis, which may include local basisdifferentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After theseadjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $49.34 per barrelfor oil and $2.27 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines. 1BEconomic ParametersOwnership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gasshrinkage, ad valorem taxes, severance taxes, lease operating expenses and investments were calculated and prepared by MCEP andwere reviewed by us for reasonableness. Lease operating expenses were either determined at the field or individual well level usingaverages calculated from historical lease operating statements. All economic parameters, including lease operating expenses andinvestments, were held constant (not escalated) throughout the life of these properties. 2BSEC Conformance and RegulationsThe reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 6 and 7 following thisletter. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royaltiescurrently in effect except as noted herein. Government policies and market conditions different from those employed in this report maycause (1) the total quantity of oil or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capitalcosts to vary from those presented in this report. However, we do not anticipate nor are we aware of any legislative changes orrestrictive regulatory actions that may impact the recovery of reserves. This evaluation includes 86 proved undeveloped cases in various fields in Texas and Oklahoma but only 51 of these represent new drilled producingwellbores (drilling locations) with the remainder Mid-Con Energy Partners, LPReserve AuditJanuary 22, 2018Page 3 representing additional reserves associated with recompletions, conversions to injectors and water flooding of existing wellbores. Eachof these drilling locations proposed as part of MCEP’s development plans conforms to the proved undeveloped standards as set forthby the SEC. In our opinion, MCEP has indicated they have every intent to complete this development plan within the next five years.Furthermore, MCEP has demonstrated that they have the proper company staffing, financial backing and prior development success toensure this five year development plan will be fully executed. 3BReserve Estimation MethodsThe methods employed in estimating reserves are described in page 5 following this letter. Reserves for proved developed producing wells were estimatedusing production performance methods for the vast majority of properties. Certain new producing properties with very little productionhistory were forecast using a combination of production performance and analogy to similar production, both of which are consideredto provide a relatively high degree of accuracy. Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or acombination of both. For certain fields either being waterflooded or prepared for a waterflood, proved undeveloped reserves werebased upon results from either a pilot waterflood (in the field) or an analogous, nearby waterflood deemed to be relevant. Thesemethods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undevelopedreserves for MCEP properties, due to the mature nature of their properties targeted for development and an abundance of subsurfacecontrol data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this audit. 4BGeneral DiscussionAn on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells andtheir related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. (“CG&A”).Possible environmental liability related to the properties has not been investigated or considered. The cost of plugging and the salvagevalue of equipment at abandonment have not been included. The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. Tosome extent information from public records has been used to check and/or supplement these data. The basic engineering andgeological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that wouldcause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the dataavailable at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions,it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual costincurred could be more or less than the estimated amounts. It should be understood that our audit and the development of our reserves forecasts do not constitute a complete reservestudy of the oil and gas properties of MCEP. In the conduct of our audit, we have not independently verified the accuracy andcompleteness of information and data furnished by MCEP with respect to ownership interests, oil and gas production, historical costsof operation and developments, product prices, agreements relating to current and future operations and sales ofproduction. Furthermore, if in the course of our examination something came to our attention which brought into question the validityor sufficiency of any of such information or data, we did not rely on Mid-Con Energy Partners, LPReserve AuditJanuary 22, 2018Page 4 such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information ordata. Please be advised that, based upon the foregoing, in our opinion the above-described estimates of Mid-Con Energy Partners,LP’s total proved reserves are, in the aggregate, reasonable within the established audit tolerance guidelines of (+ or –) 10%. Also,these estimates have been prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forthin the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society ofPetroleum Engineers and as mandated by the SEC. Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registeredprofessional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years.This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas LicensedProfessional Engineer (License #83462). We do not own an interest in the properties or Mid-Con Energy Partners, LP and are notemployed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances toprepare this audit. Our work-papers and related data utilized in the preparation of these estimates are available in our office. Sincerely, W. Todd Brooker, P.EPresident Robert P. Bergeron, Jr., P.E Senior Reservoir Engineer Mid-Con Energy Partners, LPReserve AuditJanuary 22, 2018Page 5 Methods Employed in the Estimation of Reserves The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Mostestimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs. Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of informationavailable on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and reportperiodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological andengineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in theaccuracy and reliability of estimates. A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows: Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date willcontinue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production canusually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted productioncan, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generallyconsidered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates. Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initialhydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to productionrelationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balancemethod is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirscan be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoirtypes require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there iseconomic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of thereservoir and the quality and quantity of data available. Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data requiredare well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable toreservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depletingreservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and aknowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can berelatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated. Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration oftheoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliableestimation of future reserves with a relatively high degree of accuracy. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserveestimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy. Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additionalinformation becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtainedabout well and reservoir performance. Mid-Con Energy Partners, LPReserve AuditJanuary 22, 2018Page 6 Reserve Definitions and Classifications The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requiresadherence to the following definitions of oil and gas reserves: "(22)Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience andengineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economicconditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal isreasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or theoperator must be reasonably certain that it will commence the project within a reasonable time. "(i)The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacentundrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of availablegeoscience and engineering data. "(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a wellpenetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. "(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) 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 thehigher contact with reasonable certainty. "(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) areincluded in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, theoperation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineeringanalysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. "(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be theaverage price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-monthprice for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. "(6)Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: “(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared tothe cost of a new well; and “(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving awell. "(31)Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered fromnew wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. “(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production whendrilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. “(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled tobe drilled within five years, unless the specific circumstances, justify a longer time. “(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or otherimproved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined inparagraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. Mid-Con Energy Partners, LPReserve AuditJanuary 22, 2018Page 7 "(18)Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, togetherwith proved reserves, are as likely as not to be recovered. “(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plusprobable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probablereserves estimates. “(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are lesscertain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that arestructurally higher than the proved area if these areas are in communication with the proved reservoir. “(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in placethan assumed for proved reserves. “(iv)See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below). "(17)Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. “(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probableplus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the provedplus probable plus possible reserves estimates. “(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data areprogressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial productionfrom the reservoir by a defined project. “(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recoveryquantities assumed for probable reserves. “(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercialinterpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. “(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the sameaccumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetratedby a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that arestructurally higher or lower than the proved area if these areas are in communication with the proved reservoir. “(vi)Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potentialexists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can beestablished with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable andpossible oil or gas based on reservoir fluid properties and pressure gradient interpretations.” Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gasproducing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant ispermitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.” "(26)Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a givendate, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right toproduce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement theproject. “Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated aseconomically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir,structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).” 

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