Mid-Con Energy Partners, LP
2013 Annual Report
Mid-Con Energy Partners, LP
Mid-Con Energy Partners, LP is a Delaware limited partnership formed in
December 2011 to own, operate, acquire, exploit and develop producing oil and natural
gas properties in North America, with a focus on the Mid-Continent region of the United
States. Mid-Con Energy’s core areas of operation are located in Southern Oklahoma,
Northeastern Oklahoma and parts of Oklahoma and Colorado within the Hugoton Basin.
Dear Fellow Unitholders:
We began 2013 much like we initiated our
existence as a publicly traded partnership in
December of 2011, with the singular goal of
serving our unitholders. In our view, your
interest in secure, growing distributions
continues to be best served by a portfolio of
wide margin, low risk assets operated
efficiently.
With these characteristics in mind, we are
pleased to report 2013 was successful:
Reserves and production respectively grew
by 6% and 33% per annum while our
leverage remained the lowest among
Upstream MLPs. Combined with public
transparency and responsible operation,
Mid-Con Energy Partners delivered 4%
annual distribution growth to our unitholders
in 2013 at a coverage ratio of 1.22 times.
Total returns approximated 33% during the
year. The year was also one of investing in
the future as we focused on converting
select producing wells into injection wells.
Looking ahead, we plan to adhere to our
strategic objectives which champion high
quality assets and conservative business
principles operated by talented employees.
The organic development of our legacy
asset base will remain disciplined and
technically sound. Our expertise in
enhanced oil recovery—namely
waterflooding, a method of secondary
recovery—enables us to produce essentially
all oil at wide cash margins which, in 2013,
were nearly double those of our peers.
Key to our ability to capture operating
efficiencies, and also to control the timing of
our capital investments, is operatorship:
We currently operate 99% of our net
production and intend to maintain operating
influence across our properties in the future.
In concert with organic development,
acquisitions are a core pillar of our growth
strategy. We benefit from the visibility and
operating synergies borne out of
prospective dropdown acquisitions from
Mid-Con Energy affiliates, namely Mid-Con
Energy III, LLC, privately held by our
Founders and private equity sponsor,
Yorktown Energy Partners (“Yorktown”).
Within the acquisition and divestiture
markets, we target quality assets which can
be acquired at fair market prices.
Importantly, because the structure of our
Partnership does not include Incentive
Distribution Rights, growth of Mid-Con
Energy Partners does not automatically
result in higher capital costs for our limited
partners. As of December 31, 2013, the
Founders and Yorktown collectively held
~21% of all outstanding MCEP units. In
sum, our interests and holdings are well
aligned to continue to serve the best
interests of our unitholders.
While our public entity Mid-Con Energy
Partners just completed its second full year
of operations, our predecessor was
established in 1986. Multiple cycles during
three decades in the energy market forged
us with conservatism. The cornerstone of
our capital structure is low leverage, which
in 2013 averaged 1.7 times on a debt to
adjusted EBITDA basis.
Wide margins, visible growth, low leverage
and active hedging in 2014 collectively
enhance our attractiveness to risk averse,
yield focused unitholders. We are proud of
our accomplishments in 2013, appreciative
of the opportunity to serve our unitholders
and optimistic in our outlook for Mid-Con
Energy Partners.
Sincerely,
The Founders of Mid-Con Energy GP, LLC
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________
Form 10–K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the fiscal year ended December 31, 2013
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
Commission File No.: 1-35374
________________________________________________________
Mid-Con Energy Partners, LP
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
45–2842469
(I.R.S. Employer
Identification No.)
2501 North Harwood Street, Suite 2410
Dallas, Texas 75201
(Address of principal executive offices and zip code)
(972) 479-5980
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Common Units Representing Limited Partner Interests
(Title of each class)
NASDAQ Global Select Market
(Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act: None
________________________________________________________
Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. YES
NO
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES
NO
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
NO
subject to such filing requirements for the past 90 days. YES
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). YES
NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or any
amendment to the Form 10–K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b–2 of the Exchange
Act. Check one:
Large accelerated filer
Non-accelerated filer
Accelerated filer
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act). YES
NO
The aggregate market value of the common units held by non-affiliates of the registrant was approximately $305.4 million on June 30, 2013,
based on $22.55 per unit, the last reported sales price of the units on The NASDAQ Global Select Market on such date.
Documents incorporated by Reference: None.
As of March 5, 2014 the registrant had 21,066,412 common units and 360,000 general partner units outstanding.
Table of Contents
PART I
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
PART II
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers and Corporate Governance
PART III
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
PART IV
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Exhibits
Signatures
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23
38
38
39
39
40
41
45
56
57
80
80
81
82
86
95
96
97
99
101
i
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following includes a description of the meanings of some of the oil and gas industry terms used throughout this
report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been excerpted
from the applicable definitions contained in Rule 4-10(a) of Regulation S-X.
Basin: A large depression on the earth’s surface in which sediments accumulate.
Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bbl/d: One Bbl per day.
Behind Pipe: Reserves associated with recompletion projects which have not been previously produced.
Boe: Barrel of Oil Equivalent, equals six Mcf of natural gas or one Bbl of oil based on a rough energy equivalency. This
is a physical correlation of heat content and does not reflect a value or price relationship between the commodities.
Boe/d: One Boe per day.
Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one
degree Fahrenheit.
Conventional Hydraulic Fracturing: Hydraulic fracturing is used to stimulate production from new and existing oil and
gas wells. Large volumes of fracturing fluids, or “fracing fluids,” are pumped deep into the well at high pressures sufficient to
cause the reservoir rock to break or fracture. Almost all frac fluid mixtures are comprised of more than 95 percent water. As the
pressure builds within the well, rock beds begin to crack. More fluid is added while the pressure is increased until the rock beds
finally fracture, creating channels for trapped oil and natural gas to flow into the well and up to the surface. The fractures are
kept open with proppants made of small granular solids (generally sand) to ensure the continued flow of fluids. By creating or
even restoring fractures, the surface area of a formation exposed to the borehole increases and the fracture provides a
conductive path that connects the reservoir to the well. These new paths increase the rate that fluids can be produced from the
reservoir formations, in some cases by many hundreds of percent.
Developed Acreage: Acres spaced or assigned to productive wells or wells capable of production.
Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic
horizon known to be productive.
Dry Hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the
sale of such production would exceed production expenses and taxes.
EPA: United States Environmental Protection Agency.
Exploitation: Drilling or other projects that may target proven or unproven reserves (such as probable or possible
reserves), but that generally have a lower risk than that associated with exploration projects.
Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new
reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Field: An area comprised of multiple leases in close proximity to one another that typically produce from the same
reservoirs and may or may not be produced under waterflood.
Injection Well: A well employed for the introduction into an underground stratum of water, gas or other fluid under
pressure.
MBbls: One thousand Bbls.
MBoe: One thousand Boe.
MBtu: One thousand Btu.
MBoe/d: One thousand Boe per day.
Mcf: One thousand cubic feet of natural gas.
Mcf/d: One thousand cubic feet of natural gas per day.
1
MMBoe: One million Boe.
MMBtu: One million Btu.
MMcf: One million cubic feet of natural gas.
NGLs: Natural gas liquids.
Net Production: Production that is owned by us, less royalties and production due others.
Net Revenue Interest: A working interest owner’s gross working interest in production, less the royalty, overriding royalty,
production payment and net profits interests.
NYMEX: New York Mercantile Exchange.
Oil: Oil, condensate and natural gas liquids.
Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing
equipment and operating methods.
Proved Reserves: Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to
operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic
methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be
reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved
includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the
reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or
gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a
reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering or
performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from
well penetrations has defined a highest known oil, 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 the higher contact with reasonable certainty. Reserves which can be produced
economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included
in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more
favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or
other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or
program was based; and (ii) the project has been approved for development by all necessary parties and entities, including
governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir
is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period
covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month
within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on
undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Under no circumstances should estimates for proved
undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same
reservoir.
Realized Price: The cash market price, less all expected quality, transportation and demand adjustments.
Recompletion: The completion for production of an existing wellbore in another formation from that which the well has
been previously completed. Reserves associated with recompletion are also referred to as “Behind Pipe.”
Reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the
reserve determination.
2
Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or
natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres
(e.g., 40-acre spacing) and is often established by regulatory agencies.
Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.
Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved
reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”), less
future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net
revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no
provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give
effect to derivative transactions.
Unit: A contiguous geographic area that was established and approved by state oil and gas commissions for the express
purpose of secondary recovery.
Unitization: The process of obtaining approval from working interest owners, mineral owners and regulatory agencies to
conduct secondary (e.g., waterflooding) or tertiary operations.
Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called
well or borehole.
Working Interest: The operating interest that gives the owner the right to drill, produce and conduct operating activities on
the property and a share of production.
Workover: Operations on a producing well to restore or increase production.
WTI: West Texas Intermediate, also called Texas light sweet, is defined as a type of crude oil as a benchmark in oil price
and is the underlying commodity of New York Mercantile Exchanges oil future contracts.
3
As used in this Form 10-K, unless we indicate otherwise:
NAMES OF ENTITIES
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“Founders” collectively refers to Charles R. Olmstead, S. Craig George and Jeffrey R. Olmstead;
“our general partner” refers to Mid-Con Energy GP, LLC;
“Mid-Con Affiliates” collectively refers to Mid-Con Energy III, LLC and Mid-Con Energy IV, LLC, which are
affiliates of our general partner;
“Mid-Con Energy Partners,” the “partnership,” “we,” “our,” “us” or like terms when used refer to Mid-Con
Energy Partners, LP, a Delaware limited partnership, and its subsidiaries;
“Mid-Con Energy Operating” refers to Mid-Con Energy Operating, LLC., an affiliate of our general partner;
“Mid-Con Energy Properties” refers to Mid-Con Energy Properties, LLC, our wholly owned subsidiary;
“our predecessor” collectively refers to Mid-Con Energy Corporation, prior to June 30, 2009, and to Mid-Con
Energy I, LLC and Mid-Con Energy II, LLC, on a combined basis, thereafter, our respective predecessors for
accounting purposes; and
“Yorktown” collectively refers to Yorktown Partners LLC, Yorktown Energy Partners VI, L.P., Yorktown Energy
Partners VII, L.P., Yorktown Energy Partners VIII, L.P. and/or Yorktown Energy Partners IX, L.P.
4
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (“Form 10-K”) contains forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934 (each a
“forward–looking statement”). These forward–looking statements are subject to a number of risks and uncertainties, many of
which are beyond our control, which may include statements about our:
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business strategies;
ability to replace the reserves we produce through acquisitions and the development of our properties;
oil and natural gas reserves;
technology;
realized oil and natural gas prices;
production volumes;
lease operating expenses;
general and administrative expenses;
future operating results;
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;
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general economic conditions;
competition in the oil and natural gas industry;
effectiveness of risk management activities;
environmental liabilities;
counterparty credit risk;
governmental regulation and taxation;
developments in oil producing and natural gas producing countries; and
plans, objectives, expectations and intentions.
All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are
forward-looking statements. These forward-looking statements may be found in Item 1. “Business,” Item 1A. “Risk Factors,”
Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this
Annual Report on Form 10-K. In some cases, forward-looking statements can be identified by terminology such as “may,”
“will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,”
“pursue,” “target,” “continue,” “goal,” “forecast,” “guidance,” “might,” “scheduled” and the negative of such terms or other
comparable terminology.
The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations,
which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment
based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be
reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In
addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-
looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot
assure any reader that such statements will be realized or that the forward-looking events will occur. Actual results may differ
materially from those anticipated or implied in the forward-looking statements due to factors described in the “Risk Factors”
section and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date made, and
other than as required by law. We do not intend to update or revise any forward-looking statements as a result of new
information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or
persons acting on our behalf.
5
ITEM 1. BUSINESS
PART I
Mid-Con Energy Partners, LP (“we,” “our,” “us,” the “Partnership”) is a publicly held Delaware limited partnership
formed in December 2011 that engages in the acquisition, exploitation and development of producing oil and natural gas
properties in North America, with a focus on the Mid-Continent region of the United States. Our common units are traded on
the NASDAQ Global Select Market under the symbol “MCEP”. Our general partner is Mid-Con Energy GP, LLC, a Delaware
limited liability company.
Overview
We operate as one business segment engaged in the exploration, development and production of oil and natural gas
properties. Our properties are located in the Mid-Continent region of the United States in three core areas: Southern Oklahoma,
Northeastern Oklahoma and parts of Oklahoma and Colorado within the Hugoton Basin. Our properties primarily consist of
mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low production decline
rates.
Our management team has significant industry experience, especially with waterflood projects and, as a result, our
operations focus primarily on enhancing the development of producing oil properties through waterflooding. Waterflooding, a
form of secondary oil recovery, works by repressuring a reservoir through water injection and displacing or “sweeping” oil to
producing wellbores. Through the continued development of our existing properties and through future acquisitions, we will
seek to increase our reserves and production in order to maintain and, over time, increase distributions to our unitholders. Also,
in order to enhance the stability of our cash flow for the benefit of our unitholders, we generally intend to hedge a portion of
our production volumes through various commodity derivative contracts.
As of December 31, 2013, our total estimated proved reserves were approximately 13.9 MMBoe, of which approximately
98% were oil and 76% were proved developed, both on a Boe basis. As of December 31, 2013, we operated 99% of our
properties through our affiliate, Mid-Con Energy Operating and 99% of our properties were being produced under waterflood,
in each instance on a Boe basis. Our average net production for the month ended December 31, 2013 was approximately
2,496 Boe per day and our total estimated proved reserves had an average reserve-to-production ratio of approximately
15 years.
The following table summarizes information by core area regarding our estimated proved oil and natural gas reserves, and
our average net production for the month ended December 31, 2013.
Estimated
Net Proved Reserves
December 2013
Average Net
Production
Southern Oklahoma
%
Operated
(1)
%
Oil
% Proved
Developed
Boe/d
Gross
Boe/d
Net
100% 99%
69% 2,420
1,218
(MBoe)
6,255
Northeastern Oklahoma 4,341
100% 97%
Hugoton Basin
Other
Total
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3,290
100% 98%
48
13,934
88% 87%
99% 98%
79%
86%
100%
837
677
60
683
571
24
76% 3,994
2,496
Gross Active Wells
Reserve-to-
Production
Ratio (2)
Oil and
Natural
Gas
Wells
Injection
Wells
Shut-in/
Waiting on
Completion
14
17
16
5
15
97
236
54
11
398
70
65
23
3
161
57
69
43
1
170
(1)
(2)
Operated through our affiliate, Mid-Con Energy Operating.
The reserve to production ratio is calculated by dividing estimated net proved reserves as of December 31, 2013 by
average net production for the month ended December 31, 2013.
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Developments in 2013
Acquisitions
During May 2013, we acquired additional working interests in our Cushing properties located in the Northeastern
Oklahoma core areas and in certain Southern Oklahoma units. We paid approximately $27.4 million in aggregate consideration
for the interests.
Other
During April 2013, the borrowing base under our credit facility was reaffirmed at $130.0 million. No other material
terms of the original credit agreement were amended. During November 2013, the borrowing base under our credit facility was
increased from $130.0 million to $150.0 million and The Bank of Nova Scotia ("Scotiabank") was added as an additional
lender. Effective with this increase, the maturity terms of our credit facility were extended to November 2018. No other
material terms of the original credit agreement were amended.
Our Business Strategies
Our primary business objective is to generate stable cash flows, which we expect will allow us to make quarterly cash
distributions to our unitholders at the current quarterly distribution rate and, over time, to increase our quarterly cash
distributions. In addition to our hedging strategy described below, we intend to execute the following business strategies:
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Continue exploitation of our existing properties to maximize production. We plan to continue exploiting our
proved reserves to maximize production, primarily through waterflood projects and through various oil recovery
methods, including workovers, conventional hydraulic fracturing, re-stimulations, recompletions, infill drilling
and other optimization activities. We expect to continue these activities in order to maximize our production.
Pursue acquisitions of long-lived, low-risk producing properties with upside potential. We will seek to acquire
onshore properties with long-lived reserves, low production decline rates and low-risk development potential. We
also will seek to acquire properties within mature oil fields with opportunities for incremental improvements in oil
recovery through waterfloods and other recovery techniques, which we believe will offer us additional potential to
increase reserves, production and cash flow.
Capitalize on our relationship with the Mid-Con Affiliates for favorable acquisition opportunities. We expect
that the Mid-Con Affiliates will invest capital and technical staff resources to acquire and develop properties with
existing waterfloods and to identify, acquire, form and develop new waterflood projects on those properties.
Through this relationship with the Mid-Con Affiliates, we plan to avoid much of the capital, engineering and
geological risks associated with the early development of any of these properties we may acquire. While they are
not obligated to sell any properties to us and may have difficulties acquiring and developing them, we expect that
the Mid-Con Affiliates will offer to sell properties to us from time to time. We believe that the opportunity to
acquire properties from the Mid-Con Affiliates provides us with a strategic advantage over those of our
competitors who must bear a greater share of development risks themselves.
Maintain operational control and a focus on cost-effectiveness in all our operations. As of December 31, 2013,
Mid-Con Energy Operating operated 99% of our properties, as calculated on a Boe basis. We plan to continue
exercising this level of operational control over our existing properties and favor acquisitions of operated
properties in order to manage the timing and levels of our capital expenditures, development activities and
operating costs.
Reduce the impact of commodity price volatility on our cash flow through a disciplined commodity hedging
strategy. We seek to reduce the impact of commodity price volatility on our cash flow by maintaining a portfolio
of hedge contracts to help protect our ability to make distributions. As opposed to entering into commodity
derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative
contracts in connection with material increases in our estimated production and at times when we believe market
conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of
opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production
volumes or the duration of our hedge contracts when circumstances suggest that it is prudent to do so.
Maintain a balanced capital structure to allow for financial flexibility to execute our business strategies. We
intend to maintain a balanced capital structure that affords us the financial flexibility to execute our business
strategies. Our borrowing capacity under our credit facility, our access to capital markets and internally generated
cash flow provides us with the liquidity and financial flexibility to exploit organic growth opportunities and allow
us to pursue additional acquisitions of producing properties.
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Utilize compensation programs that align the interest of our management team with our unitholders. We tie the
compensation of our executives and directors directly to achieving our strategic, operating and financial goals and
have adopted compensation programs that place a significant part of the pay of each of our executives “at risk” in
the form of an annual short-term incentive award and long-term, equity-based incentive grants. The amount of the
annual short-term incentive award paid depends on our performance against financial and operating objectives as
well as the executive meeting key leadership and development standards. A portion of the compensation of the
executives is also in the form of equity awards that tie their compensation directly to creating unitholder value
over the long-term. We believe this combination of annual short-term incentive awards and long-term equity
awards aligns the incentives of our management with our unitholders.
Our Competitive Strengths
We believe that the following competitive strengths will allow us to successfully execute our business strategies and
achieve our objective of generating and growing cash available for distribution:
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An asset portfolio largely consisting of properties with existing waterflood projects with proved reserves, of
which 98% are oil, and relatively predictable production profiles that provide growth potential through ongoing
response to waterflooding and that have modest capital requirements. Our properties consist of interests in
mature fields located in Oklahoma and Colorado that have well-understood geologic features, relatively predictable
production profiles and modest capital requirements, which we believe make them well-suited for waterflood
development and for our objective of generating stable cash flow. Over 99% of our properties are being
waterflooded and over 92% have been producing continuously since 1982 or earlier. Based on production estimates
from our December 31, 2013 audited reserves, the average estimated decline rate for our existing proved developed
producing reserves is approximately 12% for 2014 and, on a compounded average decline basis, approximately
10% for the subsequent five years and approximately 8% thereafter. Further, we believe that a substantial majority
of the capital required for growth from our existing properties has already been spent. As a result, these properties
have relatively predictable production profiles and production growth potential with modest capital requirements.
The ability to further exploit existing mature properties by utilizing our waterflood expertise. Our management
team has actively operated most of our properties since 2005, and has a history of exploiting proved reserves to
maximize production, primarily through waterflood projects. Over the last eight years, we identified, initiated,
acquired, formed and developed over 23% of all new waterflood projects in the state of Oklahoma, while the next
most active competitor formed only 8% of all new waterfloods. Furthermore, our experience in the Mid-Continent
allows us to exploit synergies developed by applying knowledge of field, reservoir and play characteristics across
the region. We believe that our expertise in secondary recovery techniques will increase the level of production
from certain of our properties, particularly from existing waterflood projects, which, over time, may increase our
cash flow.
Acquisition opportunities that are consistent with our criteria of predictable production profiles with upside
potential that may arise as a result of our relationship with the Mid-Con Affiliates. We expect the Mid-Con
Affiliates to invest capital and technical staff resources to acquire and develop properties with existing projects and
to identify, acquire, form and develop new waterflood projects on their properties. While they are not obligated to
sell any properties to us and may have difficulties acquiring and developing them, we expect that the Mid-Con
Affiliates will offer to sell properties to us from time to time. Through this relationship with the Mid-Con
Affiliates, we avoid much of the capital, engineering and geological risks associated with the early development of
any of these properties we may acquire.
Access to the collective expertise of Yorktown’s employees and their extensive network of industry relationships
through our relationship with Yorktown. Yorktown is a private investment firm focused on investments in the
energy sector with more than $4.0 billion in assets under management. As of December 31, 2013, Yorktown owned
a 12.9% limited partner interest in us, making it our largest unitholder, and Yorktown Energy Partners, IX, L.P.,
owned a 50% interest in our affiliate, Mid-Con Energy Operating. With their extensive investment experience in
the oil and natural gas industry and their extensive network of industry relationships, Yorktown’s employees are
well positioned to assist us in identifying and evaluating acquisition opportunities and in making strategic
decisions.
Mid-Con Energy Operating operates 99% of our properties, which allows them to control our operating costs
and capital expenditures. As of December 31, 2013, Mid-Con Energy Operating operated 99% of our properties,
as calculated on a Boe basis, which allowed it to control our operating costs and capital expenditures. We expect to
continue exercising this level of operational control over our properties, including any properties we acquire
through future acquisitions, which allows us to better manage our operating costs and capital expenditures. This
8
•
•
substantial operational control of our producing properties also allows us to maximize the value of our properties,
helps us stabilize our cash flow and affords us better control over the timing and costs of our operations.
An enhanced ability to pursue acquisition opportunities arising from our competitive cost of capital and
balanced capital structure. Unlike our corporate competitors, we are not subject to federal income taxation at the
entity level. This attribute should provide us with a lower cost of capital compared to those competitors, thereby
enhancing our ability to compete for acquisitions of oil and, when advantageous, natural gas properties. Also our
relatively low level of indebtedness and our ability to issue additional common units and other partnership interests
in connection with these acquisitions improves our financial flexibility. As of December 31, 2013, we had an
available borrowing capacity of $38.0 million under our credit facility after giving effect to our current borrowings
of $112.0 million, providing us with other means of financing acquisition opportunities.
The range and depth of our technical and operational expertise allows us to expand both geographically and
operationally to achieve our goals. We have assembled a senior team of geologists, engineers, landmen,
accountants and operational personnel that have been successful in developing a significant number of new
waterflood projects. Collectively, our management and employees have prior waterflood experience in over 150
waterflood projects located in more than thirteen states. We have a team of over 75 employees, with senior
leadership in all production disciplines, and we have recruited a select group of younger professionals that are
being trained in our waterflood specialty. With this expertise and depth, we believe this team has the ability to
generate new waterflood projects that may become future acquisition opportunities for us. Beyond our core
strength of waterflood development, our range and depth of expertise will allow us to expand both geographically
and operationally. Although our projects to date have been focused on waterfloods in the Mid-Continent region,
our management and operational employees have significant oil and gas experience in many other regions of the
United States. Our wealth of experience enables us to pursue other types of exploitation opportunities, such as infill
drilling projects that could significantly contribute to our strategy of generating stable cash flow and, over time,
increasing our quarterly cash distributions.
Hedging Strategy
Our hedging strategy seeks to achieve more predictable cash flows and to reduce exposure to fluctuations in the price of
oil. Our hedging program’s objective is to protect our ability to make current distributions, and to allow us to be better
positioned to increase our quarterly distribution over time, while retaining some ability to participate in upward movements in
oil prices. We use a phased approach, looking approximately 36 months forward while targeting a higher hedged percentage in
the near 12 months of the period. As of December 31, 2013, we have commodity derivative contracts covering approximately
79% and 10% of our estimated average daily oil production for calendar years 2014 and 2015 (as estimated from the projection
of our oil production in our audited proved reserves as of December 31, 2013). As of December 31, 2013 all of our derivative
contracts for 2014 and 2015 are either swaps with fixed settlements or collars. The weighted average minimum prices on all of
our derivative contracts for 2014 and 2015 are $93.56 and $87.89, respectively. A “collar” is a combination of a put option we
purchase and a call option we sell. The put option portion of a collar is also referred to as a “floor.” A floor establishes a
minimum average sale price for future oil production.
In addition to our primary hedging strategy as described above, we also intend to enter into additional commodity
derivative contracts in connection with material increases in our estimated production and at times when we believe market
conditions or other circumstances suggest that it is prudent to do so as opposed to entering into commodity derivative contracts
at predetermined times or on prescribed terms. Additionally, we may take advantage of opportunities to modify our commodity
derivative portfolio to change the percentage of our hedged production volumes or the duration of our hedge contracts when
circumstances suggest that it is prudent to do so.
By removing a significant portion of price volatility associated with our estimated future oil production, we have
mitigated, but not eliminated, the potential effects of changing oil prices on our cash flow from operations for those periods.
For a further description of our commodity derivative contracts, please read “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Liquidity and Capital Resources — Derivative Contracts.”
9
Our Principal Business Relationships
Our Relationship with the Mid-Con Affiliates
The Mid-Con Affiliates acquire and develop oil and natural gas properties that are either undeveloped or that may require
significant capital investment and development efforts before they meet our criteria for ownership. As these development
projects mature, we expect to have the opportunity to acquire certain of these properties from the Mid-Con Affiliates. Through
this relationship with the Mid-Con Affiliates, we will avoid much of the capital, engineering and geological risks associated
with the early development of any of these properties we may acquire. However, the Mid-Con Affiliates may not be successful
in identifying or consummating acquisitions or in successfully developing the new properties they acquire. Further, the Mid-
Con Affiliates are not obligated to sell any properties to us and they are not prohibited from competing with us to acquire oil
and natural gas properties.
Services Agreement
Our subsidiaries and our general partner have a services agreement with Mid-Con Energy Operating. Pursuant to the
services agreement, Mid-Con Energy Operating provides certain services to us, our subsidiaries and our general partner,
including management, administrative and operational services, which include marketing, geological and engineering 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. These expenses include, among other things, salary, bonus, incentive
compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by
Mid-Con Energy Operating to us. Mid-Con Energy Operating has substantial discretion to determine in good faith which
expenses to incur on our behalf and what portion to allocate back to us. Mid-Con Energy Operating will not be liable to us for
its performance of, or failure to perform, services under the services agreement unless its acts or omissions constitute gross
negligence or willful misconduct.
Our Relationship with Yorktown
We have a valuable relationship with Yorktown, a private investment firm founded in 1991 and focused on investments in
the energy sector. Since 2004, Yorktown has made several equity investments in our predecessor. As of December 31, 2013
Yorktown owned approximately a 12.9% limited partner interest in us, making it one of our largest unitholders. Yorktown
Energy Partners IX, L.P., owns a 50% interest in our affiliate Mid-Con Energy Operating. Also, Peter A. Leidel, a principal of
Yorktown, serves on our board of directors.
Yorktown currently has more than $4.0 billion in assets under management and Yorktown’s employees have extensive
investment experience in the oil and natural gas industry. Yorktown’s employees review a large number of potential
acquisitions and are involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various
portfolio companies in which Yorktown owns interests. With their extensive investment experience in the oil and natural gas
industry and their extensive network of industry relationships, Yorktown’s employees are well positioned to assist us in
identifying and evaluating acquisition opportunities and in making strategic decisions. Yorktown is not obligated to sell any
properties to us and they are not prohibited from competing with us to acquire oil and natural gas properties. Investment funds
managed by Yorktown manage numerous other portfolio companies, including the Mid-Con Affiliates, that are engaged in the
oil and natural gas industry and, as a result, Yorktown may present acquisition opportunities to other Yorktown portfolio
companies that compete with us.
Our Areas of Operation
As of December 31, 2013, our properties were located in the Mid-Continent region of the United States in three core
areas: Southern Oklahoma, Northeastern Oklahoma and parts of Oklahoma and Colorado within the Hugoton Basin. These core
areas are each composed of multiple waterflood units that are in close proximity to one another, produce from the same or
geologically similar reservoirs and use similar waterflood methods. Focusing on these core areas allows us to apply our
cumulative technical and operational knowledge to ongoing property development and to better predict future rates of recovery.
For a discussion of the properties in our core areas, please see “Summary of Oil Properties and Projects.”
Our properties consist of mature, legacy onshore oil reservoirs, approximately 99% of the reserves of which are being
produced under waterflooding, on a Boe basis. Our properties include multiple waterflood projects with varying degrees of
maturity.
We own on average a 83% working interest across 398 gross producing (377 net) wells, 161 gross injection
(152 net) wells, and 170 gross (169 net) wells shut-in or waiting on completion and operate 99% of our properties by value, as
calculated using the standardized measure. Approximately 99% of our revenue is derived from the proceeds of oil production.
10
Our estimated proved reserves as of December 31, 2013 were approximately 13.9 MMBoe, of which approximately 98%
were oil and approximately 76% were proved developed, both on a Boe basis. For the month ended December 31, 2013, we
produced an average of approximately 2,496 Boe per day.
The following table shows our estimated net proved oil reserves for our core areas, based on a reserve report prepared by
our internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc., our independent petroleum engineers, as of
December 31, 2013, and certain unaudited information regarding production and sales of oil and natural gas with respect to
such properties:
Average Net Production
For the Month Ended
December 31, 2013
Net
(Boe/d)
% of
Total
Estimated Net Proved Reserves as of December 31, 2013
% of
Total
Proved
Reserves
MBoe
% Proved
Developed
Reserves
% Oil
PV-10 (1) (2)
($ in millions)
% of
Total
Southern Oklahoma
Northeastern Oklahoma
Hugoton
Other
All Fields
1,218
683
571
24
2,496
49 %
27 %
23 %
1 %
6,255
4,341
3,290
48
100% 13,934
45 %
31 %
24 %
0 %
99 %
97 %
98 %
87 %
100% 98%
69 %
79 %
86 %
100 %
76%
$
$
$
$
$
237
85
68
1
391
61 %
22 %
17 %
0 %
100%
(1)
(2)
Standardized measure is calculated in accordance with Financial Accounting Standards Board Accounting Standards
Codification Topic 932, Extractive Activities—Oil and Gas. Because we are a limited partnership, we are generally
not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the
calculation of our standardized measure. For a description of our commodity derivative contracts, please read
—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and
Capital Resources—Derivative Contracts.”
Our estimated net proved reserves and standardized measure were computed by applying average trailing 12-month
index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month
within the applicable 12-month period, held constant throughout the life of the properties). These prices were
adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions and other
factors affecting the price received at the wellhead. The average trailing 12-month index prices were $96.78 per Bbl
for oil and $3.67 per MMBtu for natural gas for the 12 months ended December 31, 2013.
All proved undeveloped locations conform to SEC rules for recording proved undeveloped reserves. None of our proved
undeveloped reserves as of December 31, 2013 have remained undeveloped for more than five years from the date the reserves
were initially booked as proved undeveloped.
Summary of Oil Properties and Projects
Our core areas detailed below represent approximately 99% of our total estimated net proved reserves as of December 31,
2013, 99% of our average daily net production for the month ended December 31, 2013 and 99% of our standardized measure
as of December 31, 2013. The following is a summary of each of our properties within our core areas. All of the following
descriptions are based on our December 31, 2013 audited reserve report.
Southern Oklahoma
Our Southern Oklahoma properties are located in three fields in Love and Carter County, Oklahoma. The Southern
Oklahoma properties are part of six waterflood units operated by Mid-Con Energy Operating, four of which were unitized by
Mid-Con Energy Operating. During December 2013, our properties in these fields produced on average 2,420 Boe per day
gross, 1,218 Boe per day net, and contained 6,255 MBoe of estimated net proved reserves.
We acquired additional interests in these properties in June 2012 and May 2013 and have an average working interest of
61.5% in 97 gross producing, and 70 injection properties. During 2013, we drilled 13 gross producing wells, 5 gross injection
wells, and converted 3 producing wells to injections wells.
11
Northeastern Oklahoma
Our Northeastern Oklahoma properties are located in three fields in Pawnee, Creek, and Osage County, Oklahoma.
The majority of our properties are being produced under waterflood and are operated by Mid-Con Energy Operating. The
Cleveland Field was unitized in April 2013 as a waterflood unit. During December 2013, our properties in these fields
produced on average 837 Boe per day gross, 683 Boe per day net, and contained 4,341 MBoe of estimated net proved reserves.
We acquired additional interests in these properties in June 2012 and May 2013 and have an average working interest of 92.0%
in 236 gross producing, and 65 injection properties. During 2013 we drilled 6 gross producing wells, 3 gross injection wells, 1
gross water supply well and converted 5 producing wells to injection wells.
Hugoton Basin
Our Hugoton Basin properties are located in three fields in Texas County, Oklahoma and Cheyenne County, Colorado.
The Hugoton Basin properties are part of four waterflood units operated by Mid-Con Energy Operating, one of which Mid-Con
Energy Operating unitized. During December 2013, our properties in these units produced on average 677 Boe per day gross,
571 Boe per day net, and contained 3,290 MBoe of estimated net proved reserves. We acquired additional working interests in
October 2012, acquired one of the waterflood units in November 2012, and have an average working interest of 99.7% in 54
gross producing, and 23 injection properties. During 2013 we drilled 3 gross producing wells and converted 2 producing wells
to injection wells.
Other Properties
The balance of the Company’s properties, located throughout the state of Oklahoma, consist of a mix of operated and
non-operated properties, a majority of which are under waterflood. As of December 31, 2013, our other properties contained
approximately 48 MBoe of estimated net proved reserves and generated average net production of approximately 24 Boe per
day for the month ended December 31, 2013.
Oil and Natural Gas Reserves and Production
Internal Controls Relating to Reserve Estimates
We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and
timeliness of the data used in our reserves estimation process. Our policies regarding internal controls over the recording of
reserves estimates require reserve estimates to be in compliance with the SEC rules, regulations, definitions and guidance. Our
proved reserves are estimated at the well or unit level and compiled for reporting purposes by our reservoir engineering staff.
Internal evaluations of our reserves are maintained in a secure reserve engineering database. Reserves are reviewed internally
by our senior management on a quarterly basis. Our reserve estimates are audited by our independent third-party reserve
engineers, Cawley, Gillespie & Associates, Inc., at least annually.
Our staff works closely with Cawley, Gillespie & Associates, Inc., to ensure the integrity, accuracy and timeliness of data
that is furnished to them for their reserve audit process. To facilitate their audit of our reserves, we provide Cawley, Gillespie &
Associates, Inc. with any information they may request, including all of our reserve information as well as geologic maps, well
logs, production tests, material balance calculations, well performance data, operating procedures, lease operating expenses,
product pricing, production taxes and relevant economic criteria. We also make all of our pertinent personnel available to
Cawley, Gillespie & Associates, Inc. to respond to any questions they may have.
Technology Used to Establish Proved Reserves
Under the SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and
engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from
known reservoirs, and under existing economic conditions, operating methods and government regulations. The term
“reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will
equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by
actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology
that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational
methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and
repeatability in the formation being evaluated or in an analogous formation.
To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and
Cawley, Gillespie & Associates, Inc. employ technologies that have been demonstrated to yield results with consistency and
repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to,
12
electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, injection data,
seismic data and well test data. Reserves attributable to producing properties with sufficient production history are estimated
using appropriate decline curves or other performance relationships. Reserves attributable to producing properties with limited
production history and for undeveloped locations are estimated using performance from analogous properties in the
surrounding area and geologic data to assess the reservoir continuity. These properties were considered to be analogous based
on production performance from the same formation and similar completion techniques.
Qualifications of Responsible Technical Persons
Cawley, Gillespie & Associates, Inc. is an independent oil and natural gas consulting firm. No director, officer, or key
employee of Cawley, Gillespie & Associates, Inc. has any financial ownership in the Mid-Con Affiliates, Mid-Con Energy
Operating or any of their respective affiliates. Cawley, Gillespie & Associates, Inc.’s compensation for the required
investigations and preparation of its report is not contingent upon the results obtained and reported. Cawley, Gillespie &
Associates, Inc. has performed services for certain of Yorktown’s portfolio companies. The engineering audit presented in the
Cawley, Gillespie & Associates, Inc. report was overseen by Bob Ravnaas, P.E., Executive Vice President. Mr. Ravnaas is an
experienced reservoir engineer having been a practicing petroleum engineer since 1981. He has more than 30 years of
experience in reserves evaluation. Mr. Ravnaas received a BS with special honors in Chemical Engineering from the University
of Colorado at Boulder in 1979, and a M.S. in Petroleum Engineering from the University of Texas at Austin in 1981. He is a
Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers, the Society of
Petroleum Evaluation Engineers, the American Association of Petroleum Geologists and the Society of Petrophysicists and
Well Log Analysts.
Dr. Michael L. Wiggins has been our Executive Vice President, Chief Engineer since April 2013. Dr. Wiggins previously
served as President of William M. Cobb & Associates, Inc. where his expertise included reservoir studies and oil and gas
reserve evaluations and audits.
Estimated Proved Reserves
The following table presents our estimated net proved oil and natural gas reserves associated with our estimated proved
reserves attributable to our properties as of December 31, 2013, based on reserve reports prepared by our reservoir engineering
staff and audited by Cawley, Gillespie & Associates, Inc.
Oil
Net MBoe
Gas
Net MBoe
Total
Net MBoe
10,397
3,317
13,714
220
—
220
10,617
3,317
13,934
Reserve Data: (1)
Estimated proved developed reserves
Estimated proved undeveloped reserves
Total:
(1)
Our estimated net proved reserves were determined using index prices for oil and natural gas, without giving effect
to commodity derivative contracts, held constant throughout the life of the properties. The unweighted arithmetic
average first-day-of-the-month price for the prior twelve months were $96.78 per Bbl for oil and $3.67 per MMBtu
for natural gas at December 31, 2013. 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 $93.98 per Bbl of oil and $5.00 per Mcf of natural gas.
The data in the table above represent estimates only. Oil and gas reserve engineering is inherently a subjective process of
estimating underground accumulations of oil that cannot be measured exactly. The accuracy of any reserve estimate is a
function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve
estimates may vary from the quantities of oil that are ultimately recovered. For a discussion of risks associated with internal
reserve estimates, see “Item 1A. Risk Factors — Risks Related to Our Business.” Our estimated proved reserves and future
production rates rely on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.
Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for
purposes of these estimates. The standardized measure amounts should not be construed as the current market value of our
estimated oil reserves. The 10% discount factor used to calculate standardized measure, which is required by Financial
Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter
13
what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be
inaccurate.
Production, Revenue and Price History
For a description of the Partnership’s and the Predecessor’s historical production, revenues and average sales prices and
unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of
Operations.”
Development of Proved Undeveloped Reserves
None of our proved undeveloped reserves at December 31, 2013, are scheduled to be developed on a date more than five
years from the date the reserves were initially booked as proved undeveloped. Consistent with the typical waterflood response
time range of six to eighteen months from initial development, the transfer of proved undeveloped reserves to the proved
developed category through drilling is attributable to development costs incurred in prior years. During 2013, our capital
expenditures for development drilling were approximately $14.5 million. Based on our current expectations of our cash flow,
we believe that we can fund the development of our proved undeveloped reserves associated with our waterflood operations
from our cash flow from operations and, if needed, borrowings from our credit facility. For a more detailed discussion of our
pro forma liquidity position, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Liquidity and Capital Resources.”
Development Activities
Since January 2013, we have undertaken an extensive program consisting of drilling approximately 31 gross (24 net)
development wells, the majority of which reside in our Southern and Northeastern Oklahoma core areas. Approximately 26%
of these development wells are injection wells and the remainders are producing wells with 1 water supply well. The program
has continued to successfully support injection and production and will continue on into 2014.
In our Northeastern Oklahoma core area, since early 2010, we have been engaged in an active acquisition and
corresponding exploitation program in our Cleveland Field. During 2013, we unitized our Cleveland Field operations. The
unitization has allowed us to enhance our exploitation strategy for these properties with a positive impact on production.
The following table sets forth information with respect to development activities during the periods indicated. The
information should not be considered indicative of future performance nor should a correlation be assumed between the number
of productive wells drilled, quantities of reserves found or economic value.
Developmental wells:
Productive
Injection
Water Supply
Dry
Exploratory wells:
Productive
Dry
Total wells:
Productive
Injection
Water Supply
Dry
Total:
2013
2012
2011
Gross
Net
Gross
Net
Gross
Net
Year Ended December 31,
22
8
1
—
—
—
22
8
1
—
31
17
6
1
—
—
—
17
6
1
—
24
31
7
—
1
—
—
31
7
—
1
39
23
6
—
1
—
—
23
6
—
1
30
34
12
—
2
—
—
34
12
—
2
48
21
9
—
1
—
—
21
9
—
1
31
We are in the process of completing 3 gross (3 net) recently drilled wells in our Northeastern Oklahoma core area.
14
Productive Wells
The following table sets forth information relating to the productive wells in which we owned a working interest as of
December 31, 2013. Productive wells consist of producing wells and wells capable of production, including natural gas wells
awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells
are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working
interests owned in gross wells.
Oil
Natural Gas
Injection
Water Supply
Wells
Shut-in /
Waiting on
Completion
Total Wells
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Operated
Non-operated
Total
394
4
398
376
—
376
4
3
7
1
—
1
161
—
161
152
—
152
14
—
14
12
—
12
170
—
170
169
—
169
739
4
743
710
—
710
Developed Acreage
The following table sets forth information relating to our leasehold acreage. Acreage related to royalty, overriding royalty
and other similar interests is excluded from this table. As of December 31, 2013, substantially all of our leasehold acreage was
held by production:
Southern Oklahoma
Northeastern Oklahoma
Hugoton Basin
Other
Total
Delivery Commitments
Developed Acreage
Gross
Net
8,744
6,319
9,232
1,281
25,576
5,381
5,811
9,203
763
21,158
We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production in the near
future under our existing contracts.
Operations
General
We operate approximately 99% of our properties, as calculated on a Boe basis as of December 31, 2013, through our
affiliate, Mid-Con Energy Operating. All of our non-operated wells are managed by third-party operators who are typically
independent oil and natural gas companies. We design and manage the development, recompletion or workover 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 in each of our core areas to provide all of the equipment and personnel
associated with our drilling and maintenance activities, including well servicing, trucking and water hauling, bulldozing, and
various downhole services (e.g., logging, cementing, perforating and acidizing). These services are short-term in duration
(often being completed in less than a day) and are typically governed by a one-page service order that states only the parties’
names, a brief description of the services and the price.
We also engage several independent contractors to provide hydraulic fracturing services. These services are usually
completed in four to six hours utilizing lower pressures and volumes of fluid than are typically employed in connection with
multi-stage hydraulic fracturing jobs performed in connection with unconventional oil and gas shale plays. These services are
not normally governed by long-term services contracts, but instead are generally performed under one-time service orders,
which state the parties’ names and the price. These service orders sometimes contain additional terms addressing, 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.
15
Geological and Engineering Services
Mid-Con Energy Operating employs production and reservoir engineers, geologists and land specialists, as well as field
production supervisors. Through the services agreement, we have the direct operational support of a staff of over 26 petroleum
professionals with significant technical expertise. We believe that this technical expertise, which includes extensive experience
utilizing secondary recovery methods, particularly waterfloods, differentiates us from, and provides us with a competitive
advantage over, many of our competitors. Please read “Certain Relationships and Related Party Transactions — Services
Agreement.”
Administrative Services
Mid-Con Energy Operating provides us with management, administrative and operational services under the services
agreement. We reimburse Mid-Con Energy Operating, on a cost basis, for the allocable expenses it incurs in performing these
services. Mid-Con Energy Operating has substantial discretion to determine in good faith which expenses to incur on our behalf
and what portion to allocate to us. For a detailed description of the administrative services provided by Mid-Con Energy
Operating pursuant to the services agreement, please read “Certain Relationships and Related Party Transactions — Services
Agreement.”
Oil and Natural Gas Leases
The typical oil lease agreement covering our properties provides for the payment of royalties to the mineral owner for all
hydrocarbons produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on our
properties range from less than 10% to 33%, resulting in a net revenue interest to us ranging from 67% to 87.5%, or 84.1% on
average, on a 100% working interest basis. Most of our leases are held by production and do not require lease rental payments.
Principal Customers
For the year ended December 31, 2013, sales of oil and natural gas to Enterprise Crude Oil, LLC (“Enterprise”),
Coffeyville Resources Refining & Marketing, LLC ("Coffeyville"), and Valero Marketing & Supply Co. ("Valero") accounted
for approximately 50%, 23%, and 9%, respectively, of our sales volumes.
The loss of any of our customers could temporarily delay production and sale of our oil and natural gas. If we were to lose
any of our significant customers, we believe that under current market conditions, we could identify substitute customers to
purchase the impacted production volumes. However, if any of our customers dramatically decreased or ceased purchasing oil
from us, we may have difficulty finding substitute customers to purchase our production volumes at comparable rates.
Hedging Activities
We continue to enter into commodity derivative contracts with unaffiliated third parties that are also members of our
banking group to achieve more predictable cash flow and to reduce our exposure to short-term fluctuations in oil and natural
gas prices. All of our derivative contracts for 2014 and 2015 are either swaps with fixed settlements or collars (calls and puts)
with NYMEX prices and option agreements. For a more detailed discussion of our hedging activities, see “Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources”
and “Item 7A. Quantitative and Qualitative Disclosure About Market Risk.”
Competition
We operate in a highly competitive environment for acquiring properties and securing trained personnel. Many of our
competitors possess and employ financial resources substantially greater than ours, which can be particularly important in the
areas in which we operate. Some of our competitors may also possess greater technical and personnel resources than us. As a
result, our competitors may be able to pay more for productive oil properties and exploratory prospects, as well as evaluate, bid
for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to
acquire additional properties and to acquire and develop reserves will depend on our ability to evaluate and select suitable
properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for
capital available for investment in the oil and natural gas industry.
We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment and
services. In recent years, the United States onshore oil and natural gas industry has experienced shortages of drilling and
completion rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and
caused significant increases in the price for this equipment and personnel. We are unable to predict when, or if, such shortages
may occur or how they would affect our development and exploitation programs.
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Title to Properties
Prior to completing an acquisition of producing oil properties, we perform title reviews on significant leases, and
depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a
result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the
assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.
We initially conduct only a review of the titles to our properties on which we do not have proved reserves. Prior to the
commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work
with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties we
are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a
property until we have cured any material title defects on such property.
We believe that we have satisfactory title to all of our material properties. Although title to these properties is subject to
encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property,
customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental
liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor
encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens
and encumbrances will materially detract from the value of these properties or from our interest in these properties or
materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have
obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business.
Hydraulic Fracturing
Hydraulic fracturing has been a routine part of the completion process for the majority of the wells on our producing
properties in Oklahoma and Colorado for several decades. Most of our properties are dependent on our ability to hydraulically
fracture the producing formations. We are currently conducting hydraulic fracturing activities in our Northeastern Oklahoma
and Southern Oklahoma core areas. All of our leasehold acreage is currently held by production from existing wells. Therefore,
fracturing is not currently required to maintain this acreage but it will be required in the future to develop the majority of our
proved behind pipe and proved undeveloped reserves associated with this acreage. Nearly all of our proved behind pipe and
proved undeveloped reserves associated with future drilling and recompletion projects, or 33% of our total estimated proved
reserves as of December 31, 2013 will be subject to hydraulic fracturing. Although the cost of each well will vary, on average
approximately 12.5% of the total cost of drilling and completing a well is associated with hydraulic fracturing activities. These
costs are treated in the same way that all other costs of drilling and completing our wells are treated and are built into and
funded through our normal capital expenditure budget.
For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related
environmental matters, please read “Item 1. Business -Environmental Matters and Regulation-Water Discharges.” For related
risks to our unitholders, please read “Item 1A. Risk Factors-Risks Related to Our Business.” Federal and State legislative and
regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or
delays.
Insurance
We maintain insurance coverage against potential losses that we believe is customary in the industry. We currently
maintain general liability insurance and commercial umbrella liability insurance with limits of $1.0 million and $5.0 million per
occurrence, respectively, and $2.0 million and $5.0 million in the aggregate, respectively. There is a $1,000 per claim
deductible for only our property damage liability and our containment and pollution coverage included as part of our general
liability insurance and a $10,000 retention for our commercial umbrella liability insurance. Our general liability insurance
covers us for, among other things, legal and contractual liabilities arising out of property damage and bodily injury, for sudden
or accidental pollution liability. Our commercial umbrella liability insurance is in addition to, and triggered if, the general
liability insurance policy limits are exceeded. In addition, we maintain control of well insurance with per occurrence limits of
$5.0 million and retentions of $50,000. Our control of well policy insures us for blowout risks associated with drilling,
completing and operating our wells, including above ground pollution.
Our insurance policies may not cover fines, penalties or costs and expenses related to government mandated clean-up of
pollution. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance
coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we
consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results
of operations and cash flows.
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Environmental Matters and Regulation
General
Our operations are subject to stringent and complex federal, tribal, state and local laws and regulations governing
environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among
other things (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) govern the
types, quantities and concentration of various substances that can be released into the environment or injected into formations
in connection with oil drilling and production activities; (iii) restrict the way we handle or dispose of our wastes; (iv) limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (v) require investigatory
and remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug
abandoned wells; and (vi) impose obligations to reclaim and abandon wellsites. Any failure to comply with these laws and
regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of corrective or remedial
obligations, and the issuance of orders enjoining performance of some or all of our operations.
These laws and regulations may also restrict the rate of production below the rate that would otherwise be possible. The
regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently
affects profitability. Additionally, the U.S. Congress and federal and state agencies frequently revise environmental laws and
regulations, and any changes that result in more stringent and costly waste handling, storage, transport, drilling, disposal, and
remediation requirements for the oil and natural gas industry could have a significant impact on our operating costs.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the
environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that
result in more stringent and costly waste handling, storages, transport, drilling disposal, or remediation requirements could have
a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased
compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we
cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-
party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with
existing environmental laws and regulations and that continued compliance with existing requirements will not materially
affect us, we can provide no assurance that we will not incur substantial costs in the future related to revised or additional
environmental regulations that could have a material adverse effect on our business, financial condition and results of
operations.
The following is a summary of the more significant existing environmental, health and safety laws and regulations to
which our business operations are subject and for which compliance may have a material adverse impact on our capital
expenditures, results of operations or financial position.
Hazardous Substances and Waste
The federal Resource Conservation and Recovery Act, as amended, (“RCRA”), and comparable state statutes and their
respective implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of
RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek
to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state
requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and
production of oil, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes,
instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. However, it is
possible that certain oil exploration, development and production wastes now classified as non-hazardous could be classified as
hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes,
which could have a material adverse effect on our results of operations and financial position.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known
as the Superfund law and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of
persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the
current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal
of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability
for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural
resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to
act in response to threats to public health or the environment and to seek to recover from responsible classes of persons the
costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances or other pollutants released into the environment. Despite the
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so-called petroleum exclusion, we generate materials in the course of our operations that may be regulated as hazardous
substances.
We currently own, lease, or operate numerous properties that have been used for oil and/or natural gas exploration,
production and processing for many years. Although we believe that we have utilized operating and waste disposal practices
that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under
or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such
substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous
owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control.
These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA, and
analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including
wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated
groundwater) and to perform remedial operations to prevent future contamination.
Water Discharges
The federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws,
impose restrictions and strict controls regarding the discharge of pollutants, including oil and hazardous substances, into state
waters and federal navigable waters in the United States. The discharge of pollutants into federal or state waters is prohibited,
except in accordance with the terms of a permit issued by the EPA or an analogous state or tribal agency that has been delegated
authority for the program by the EPA. Federal, state and tribal regulatory agencies can impose administrative, civil and criminal
penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and
regulations. Plan requirements imposed under the Clean Water Act require appropriate containment berms and similar
structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In
addition, the Clean Water Act and analogous state laws required individual permits or coverage under general permits for
discharges of storm water runoff from certain types of facilities.
The Oil Pollution Act of 1990, as amended (“OPA”), or the OPA, amends the Clean Water Act and establishes strict
liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. The OPA and
its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and
liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain
onshore facilities from which a release may affect waters of the United States
The Safe Drinking Water Act, as amended, (the “SDWA”) and analogous state laws impose requirements relating to our
underground injection activities. Under these laws, the EPA and state environmental agencies have adopted regulations related
to permitting, testing, monitoring, record-keeping and reporting of injection well activities, as well as prohibitions against the
migration of injected fluids into underground sources of drinking water. We currently own and operate a number of injection
wells, used primarily for reinjection of produced waters that are subject to SDWA requirements.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil
from dense subsurface rock formations. We employ conventional hydraulic fracturing techniques to increase the productivity of
certain of our properties. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure
into rock formations to fracture the surrounding rock and stimulate production. The hydraulic fracturing process is typically
regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over certain
hydraulic fracturing activities involving diesel under the SDWA and has published draft guidance documents related to this
newly asserted regulatory authority. In addition, Congress has considered federal regulation of hydraulic fracturing including
disclosure of the chemicals used in the hydraulic fracturing process. Several states in which we operate including Texas and
Oklahoma have adopted rules requiring the disclosure of certain information related to hydraulic fluids associated with
horizontal wells that are hydraulically fractured. Additionally, some states, and local governments have adopted and other
states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. For example, the
state of Arkansas established a moratorium on waste water injection in certain areas hydraulic fracturing activities due to
concern that such activities may be related to increased earthquake activity. Other authorities are considering restrictions on the
disposal of hydraulic fluids by deepwell injection. We follow applicable industry standard practices and legal requirements for
groundwater protection in our hydraulic fracturing activities. In the event that new or more stringent federal, state or local legal
restrictions are adopted in areas where we operate, we could incur potentially significant added costs to comply with such
requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities.
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There are certain governmental reviews either underway or being proposed that focus on environmental aspects of
hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a
variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential
environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected by 2014. The EPA
has also announced that it is launching a study regarding the disposal of wastewater resulting from hydraulic fracturing
activities into surface water and currently plans to propose standards by 2014 that such wastewater must meet before being
transported to a treatment plant. The U.S. Department of Energy is conducting an investigation of practices the agency could
recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These ongoing or
proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further
regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.
Almost all of our hydraulic fracturing operations are conducted on vertical wells. The fracture treatments on these wells
are much smaller and utilize much less water than what is typically used on most of the shale gas wells that are being drilled
throughout the United States. We follow applicable industry standard practices and legal requirements for groundwater
protection in our operations, subject to close supervision by state and federal regulators, which conduct many inspections
during operations that include hydraulic fracturing. We minimize the use of water and dispose of the produced water into
approved disposal or injection wells. We currently do not intentionally discharge water to the surface.
Air Emissions
The federal Clean Air Act, as amended and comparable state laws regulate emissions of various air pollutants through air
emissions standards, construction and operating permitting programs and the imposition of other compliance requirements.
These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or
facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit
requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to
delay the development of our projects.
While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment
or other air emissions-related issues, we do not believe that such requirements will have a material adverse effect on our
operations. For example, on August 16, 2012, the EPA published final regulations under the Clean Air Act that, among other
things, require additional emissions controls for natural gas and natural gas liquids production, including New Source
Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of
emission standards to address hazardous air pollutants frequently associated with such production activities. The final
regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or
“green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion
operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct
flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These
regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production
equipment. Compliance with these requirements could increase our costs of development and production, though we do not
expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and
natural gas exploration and production activities.
Climate Change
In December 2009, the EPA published its findings that emissions of carbon dioxide, or CO2, methane, and other
greenhouse gases, or GHGs, present a danger to public health and the environment. Based on these findings, the EPA began
adopting and implementing regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act.
These regulations include requirements to regulate emissions of GHGs from motor vehicles, certain requirements for
construction and operating permit reviews for GHG emissions from certain large stationary sources, requiring the reporting of
GHG emissions from specified large GHG emission sources including operators of onshore oil and natural gas production and
rules requiring so-called green completions of natural gas wells beginning 2015. We are currently monitoring GHG emissions
from our operations in accordance with the GHG emissions reporting rule. Data collected from our initial GHG monitoring
activities indicated that we do not currently exceed the threshold level of GHG emissions triggering a reporting obligation. To
the extent we exceed the applicable regulatory threshold level in the future, we will report the emissions beginning in the
applicable period. Also, Congress has from time to time considered legislation to reduce emissions of GHGs and almost one-
half of the states, either individually or through multi-state regional initiatives, already have begun implementing legal
measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations
on, or limiting emissions of GHGs from, our equipment and operations could require us to incur significant costs to reduce
emissions of GHGs associated with operations or could adversely affect demand for our production.
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National Environmental Policy Act
Oil exploration, development and production activities on federal lands are subject to the National Environmental Policy
Act, as amended, (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency
actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare
an environmental assessment that analyses the potential direct, indirect and cumulative impacts of a proposed project and, if
necessary, will prepare a more detailed environmental impact statement that may be made available for public review and
comment. Currently, we have no exploration and production activities on federal lands. However, for future or proposed
exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements
of NEPA may be required. This process has the potential to delay the development of oil projects.
Endangered Species Act
The federal Endangered Species Act (“ESA”) may restrict activities that affect endangered or threatened species. Federal
agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the
continued existence of listed species or modify their critical habitat. While our facilities are located in areas that are not
currently designated as habitat for endangered or threatened species, the designation of previously unidentified endangered or
threatened species habitats could cause us to incur additional costs or become subject to operating restrictions or bans in the
affected areas. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on
September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered
under the Endangered Species Act over a period of six years. The designation of previously unprotected species in areas where
we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or
could result in limitations on our exploration and production activities that could have an adverse impact on our ability to
develop and produce our reserves.
OSHA
We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, (“OSHA”), and
comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard
communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and
similar state statutes and regulations require that we organize and/or disclose information about hazardous materials used or
produced in our operations and that this information be provided to employees, state and local governmental authorities and
citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and
safety.
Other Regulation of the Oil and Natural Gas Industry
General
Various aspects of our oil and natural gas operations are subject to extensive and frequently changing regulation as the
activities of the oil and natural gas industry often are reviewed by legislators and regulators. Numerous departments and
agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil
and natural gas industry and its individual members.
The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates, and terms and
conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive
for sales of our natural gas. FERC regulates interstate oil pipelines under the provisions of the Interstate Commerce Act, or
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 EPAct 1992. FERC is also authorized to prevent and sanction market manipulation in natural gas markets under the
Energy Policy Act of 2005. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining
price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of
natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices,
Congress could reenact price controls in the future.
In addition, the Federal Trade Commission (“FTC”), and the U.S. Commodity Futures Trading Commission (“CFTC”)
hold statutory authority to prevent market manipulation in oil and energy futures markets, respectively. Together with FERC,
these agencies have imposed broad rules and regulations prohibiting fraud and manipulation in oil and gas markets and energy
futures markets. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent
market manipulation. Failure to comply with such market rules, regulations and requirements could have a material adverse
effect on our business, results of operations, and financial condition.
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Oil and NGLs Transportation Rates
Our sales of crude oil, condensate and NGLs are not currently regulated and are transacted at market prices. In a number
of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and
conditions of service are subject to FERC jurisdiction under the ICA and EPAct 1992. The price we receive from the sale of oil
and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for oil, NGLs, and
other products are regulated by the FERC, and in general, these rates must be cost-based or based on rates in effect in 1992,
although FERC has established an indexing system for such transportation which allows such pipelines to take an annual
inflation-based rate increase. Shippers may, however, contest rates that do not reflect costs of service. The FERC has also
established market-based rates and settlement rates as alternative forms of ratemaking in certain circumstances.
In other instances involving intrastate-only transportation of oil, NGLs, and other products, the ability to transport and sell
such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state
regulatory bodies under state statutes. Such pipelines may be subject to regulation by state regulatory agencies with respect to
safety, rates and/or terms and conditions of service, including requirements for ratable takes or non-discriminatory access to
pipeline services. The basis for intrastate regulation and the degree of regulatory oversight and scrutiny given to intrastate
pipelines varies from state to state. Many states operate on a complaint-based system and state commissions have generally not
initiated investigations of the rates or practices of liquids pipelines in the absence of a complaint.
Regulation of Oil and Natural Gas Exploration and Production
Our exploration and production operations are subject to various types of regulation at the federal, state and local levels.
Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the
location of wells, the method of drilling, casing, operating, plugging and abandoning wells, notice to surface owners and other
third parties, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have
statutes or regulations addressing conservation of oil and gas resources, including provisions for the unitization or pooling of
oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the
regulation of spacing of such wells.
Oklahoma, where most of our properties are currently located, allows forced pooling or integration of tracts to facilitate
exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization
may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws
establish maximum rates of production from oil wells generally prohibit the venting or flaring of natural gas and impose
requirements regarding the ratability of production. These laws and regulations may limit the amount of oil we can produce
from our wells or limit the number of wells or the locations at which we can drill.
States also impose severance taxes and enforce requirements for obtaining drilling permits. For example, the State of
Oklahoma currently imposes a production tax and an excise tax for oil and natural gas properties. A portion of our wells in
Oklahoma currently receive a reduced production tax rate due to the Enhanced Recovery Project Gross Production Tax
Exemption. Additionally, production tax rates vary by state. States do not regulate wellhead prices or engage in other similar
direct economic regulation, but there can be no assurance that they will not do so in the future.
In 2012, there were numerous new and proposed regulations related to oil and gas exploration and production activities.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural
gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and
laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance
with these laws will have a material adverse effect on us.
Pipeline Safety
While we do not own pipelines subject to safety regulation, we rely on such pipelines to deliver our production. Federal
and state safety regulations have become increasingly more stringent over time and could affect the availability and cost of
pipeline transportation to us.
Employees
The officers of our general partner manage our operations and activities. Neither we, our subsidiaries, nor our general
partner have employees. Our general partner has entered into a services agreement with Mid-Con Energy Operating pursuant to
which Mid-Con Energy Operating will perform services for us, including the operation of our properties. Mid-Con Energy
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Operating has over 75 employees performing services for our operations and activities. We believe that Mid-Con Energy
Operating has a satisfactory relationship with these employees.
Offices
Our headquarters are located at 2501 North Harwood Street, Suite 2410, Dallas, Texas 75201, with approximately 5,400
square feet of office space under lease. Our Dallas lease expires in 2016. For our principal operating office, we currently lease
approximately 15,000 square feet of office space in Tulsa, Oklahoma at 2431 East 61st Street, Suite 850, Tulsa, Oklahoma
74136. Our Tulsa lease expires in December 2016.
Financial Information
We operate our business as a single segment. Additionally, all of our properties are located in the United States and all of
the related reserves are derived from purchases located in the United States. Our financial information is included in the
consolidated financial statements and the related notes included in “Item 8. Financial Statements and Supplementary Data.”
Available Information
Our annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on Form 8–K and amendments to
those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are
made available free of charge on our website at www.midconenergypartners.com as soon as reasonably practicable after these
reports have been electronically filed with, or furnished to, the SEC. These documents are also available on the SEC’s website
at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100
F Street, NE, Washington DC 20549. No information from either the SEC’s website or our website is incorporated herein by
reference.
ITEM 1A. RISK FACTORS
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business
risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of
the following risks were actually to occur, our business, financial condition or results of operations could be materially
adversely affected. This list is not exhaustive.
Risks Related to Our Business
We may not have sufficient cash available for distribution to sustain our current quarterly distribution, or any
distribution at all, on our units following the establishment of cash reserves and payment of expenses, including payments
to our general partner.
We may not have sufficient cash available for distribution each quarter to sustain our current quarterly distribution or any
distribution at all, on our units. Under the terms of our partnership agreement, the amount of cash available for distribution will
be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for
future operations, future capital expenditures, including development of our oil and natural gas properties, future debt service
requirements and future cash distributions to our unitholders. The amount of cash that we distribute to our unitholders will
depend principally on the cash we generate from operations, which will depend on, among other factors:
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the amount of oil and natural gas we produce;
the prices at which we sell our oil and natural gas production;
the amount and timing of settlements on our commodity derivative contracts;
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.
Further, the amount of cash we have available for distribution depends primarily on our cash flow, including cash from
financial reserves and borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may
make cash distributions during periods when we record losses for financial accounting purposes and may not make cash
distributions during periods when we record net income for financial accounting purposes.
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A decline in oil prices, or an increase in the differential between the NYMEX or other benchmark prices of oil and the
wellhead price we receive for our production, will cause a decline in our cash flow from operations, which could cause us to
reduce our distributions or cease paying distributions altogether.
Lower oil prices may decrease our revenues and therefore, our cash available for distribution to our unitholders.
Historically, oil prices have been extremely volatile. For example, during 2013, the NYMEX-WTI oil price ranged from a high
of $110.53 to a low of $86.68 per barrel. For the five years ended December 31, 2013, the NYMEX-WTI oil price ranged from
a high of $113.93 to a low of $33.98 per barrel. A significant decrease in commodity prices may cause us to reduce the
distributions we pay to our unitholders or to cease paying distributions altogether.
Also, the prices that we receive for our oil production often reflect a regional discount, based on the location of the
production, to the relevant benchmark prices, such as the NYMEX, that are used for calculating hedge positions. These
discounts, if significant, could similarly reduce our cash available for distribution to our unitholders and adversely affect our
financial condition.
If commodity prices decline and remain depressed for a prolonged period, production from a significant portion of our
development projects may become uneconomic and cause write downs of the value of our oil properties, which may
adversely affect our financial condition and our ability to make distributions to our unitholders.
Significantly lower oil prices may render many of our development projects uneconomic and result in a downward
adjustment of our reserve estimates, which would negatively impact our borrowing base and ability to borrow to fund our
operations or to pay distributions to our unitholders. As a result, we may reduce the amount of distributions paid to our
unitholders or cease paying distributions. In addition, a significant or sustained decline in oil prices could hinder our ability to
effectively execute our hedging strategy. For example, during a period of declining commodity prices, we may enter into
commodity derivative contracts at relatively unattractive prices in order to mitigate a potential decrease in our borrowing base
upon a redetermination.
Further, deteriorating commodity prices may cause us to recognize impairments in the value of our oil properties. In
addition, if our estimates of development costs increase, production data factors change or drilling results deteriorate,
accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil properties for
impairments. We may incur impairment charges in the future related to depressed oil prices, which could have a material
adverse effect on our results of operations in the period taken.
Our hedging strategy may be ineffective in mitigating the impact of commodity price volatility on our cash flows,
which could result in financial losses or could reduce our income, which may adversely affect our ability to pay
distributions to our unitholders.
We intend to maintain a portfolio of commodity derivative contracts covering a portion of our near-term estimated oil
production. The prices at which we are able to enter into commodity derivative contracts covering our production in the future
will be dependent upon oil prices at the time we enter into these transactions, which may be substantially higher or lower than
current oil prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil prices received for
our future production.
Our credit facility may hinder our ability to effectively execute our hedging strategy. To the extent our credit facility
limits the maximum percentage of our production that we can hedge or the duration of those hedges, 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. Conversely, while our credit facility may not require us to hedge a minimum
percentage of our production, it may cause us to enter into commodity derivative contracts at inopportune times. For example,
during a period of declining commodity prices, we may enter into commodity derivative contracts at relatively unattractive
prices in order to mitigate a potential decrease in our borrowing base upon a redetermination.
Our hedging activities could result in cash losses and may limit the prices we would otherwise realize for our
production, which could reduce our cash available for distribution.
Our hedging strategy may limit our ability to realize cash flows from commodity price increases. Many of our derivative
contracts require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting
our ability to realize the benefit of increases in oil prices. If our actual production and sales for any period are less than our
hedged production and sales for that period (including reductions in production due to operational delays), we might be forced
to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying
physical commodity, which may materially impact our liquidity and our cash available for distribution to our unitholders
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Our hedging transactions expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract.
Disruptions in the financial markets could lead to a sudden decrease in a counterparty’s liquidity, which could impair its ability
to perform under the terms of the derivative contract and, accordingly, prevent us from realizing the benefit of the derivative
contract.
Unless we replace the oil reserves we produce, our revenues and production will decline, which would adversely affect
our cash flow from operations and our ability to make distributions to our unitholders at the initial quarterly distribution
rate.
We may be unable to sustain our current quarterly distribution rate without substantial capital expenditures that maintain
our asset base. Producing oil reservoirs are characterized by declining production rates that vary depending upon reservoir
characteristics and other factors. Our future oil reserves and production and, therefore, our cash flow and ability to make
distributions are highly dependent on our success in economically finding or acquiring recoverable reserves and efficiently
developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently
estimated if our wells do not produce as expected. Further, our decline rate may change when we make acquisitions. We may
not be able to develop, find or acquire additional reserves to replace our current and future production on economically
acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash
available for distribution to our unitholders.
Our operations require substantial capital expenditures, which will reduce our cash available for distribution and
could materially affect our ability to make distributions to our unitholders
We make and expect to continue to make substantial capital expenditures for the development, production and acquisition
of oil reserves. Some of these expenditures will reduce our cash available for distribution. Further, if the borrowing base under
our credit facility or our revenues decrease as a result of lower oil prices, declines in estimated reserves or production or for any
other reason, we may not be able to obtain the capital necessary to sustain our operations at the expected levels so as to
generate an amount of cash necessary to make distributions to our unitholders.
Developing and producing oil is a costly and high-risk activity with many uncertainties that could adversely affect our
business, financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
The cost of developing and operating oil properties, particularly under a waterflood, is often uncertain, and cost and
timing factors can adversely affect the economics of a well. Our efforts may be uneconomical if we drill dry holes, or if our
properties are productive but do not produce as much oil as we had estimated. Furthermore, our producing operations may be
curtailed, delayed or canceled as a result of other factors, including:
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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;
costs or delays imposed by or resulting from compliance with regulatory requirements;
fires, blowouts, surface craterings, explosions and other hazards that could also result in personal injury and loss of
life, pollution and suspension of operations; and
uncontrollable flows of oil or well fluids.
If any of these factors were to occur with respect to a particular property, we could lose all or a part of our investment in
the property, or we could fail to realize the expected benefits from the property, either of which could materially and adversely
affect our revenue and cash available for distribution to our unitholders.
We inject water into most of our properties to maintain and, in some instances, to increase the production of oil. We may
in the future employ other secondary or tertiary recovery methods in our operations. The additional production and reserves
attributable to the use of secondary recovery methods and of tertiary recovery methods are inherently difficult to predict. If our
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recovery methods do not result in expected production levels, we may not realize an acceptable return on the investments we
make to use such methods.
Hydraulic fracturing has been a part of the completion process for the majority of the wells on our producing properties,
and most of our properties are dependent on our ability to hydraulically fracture the producing formations. We engage third-
party contractors to provide hydraulic fracturing services and generally enter into service orders on a job-by-job basis. Some
such service orders limit the liability of these contractors. Hydraulic fracturing operations can result in surface spillage or, in
rare cases, the underground migration of fracturing fluids. Any such spillage or migration could result in litigation, government
fines and penalties or remediation or restoration obligations. Our current insurance policies provide some coverage for losses
arising out of our hydraulic fracturing operations. However, these policies may not cover fines, penalties or costs and expenses
related to government-mandated clean-up activities, and total losses related to a spill or migration could exceed our per
occurrence or aggregate policy limits. Any losses due to hydraulic fracturing that are not fully covered by insurance could have
a material adverse effect on our financial position, results of operations and cash flows.
Our estimated proved reserves and future production rates are based on many assumptions that may prove to be
inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the
quantities and present value of our estimated reserves.
It is not possible to measure underground accumulations of oil in an exact way. Oil reserve engineering is complex,
requiring subjective estimates of underground accumulations of oil and assumptions concerning future oil prices, future
production levels and operating and development costs. As a result, estimated quantities of proved reserves, projections of
future production rates and the timing of development expenditures may prove inaccurate. For example, if the price used in our
December 2013 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 by $64.4 million, from $391.2 million to $326.8 million.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and
present value of our reserves which could affect our business, results of operations and financial condition and our ability to
make distributions to our unitholders.
The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of
our estimated proved oil reserves.
The present value of future net cash flows from our proved reserves, or standardized measure, may not represent the
current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated
discounted future net cash flows from our estimated proved reserves on the 12-month average oil index prices, calculated as the
unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the
estimate, holding the prices and costs constant throughout the life of the properties.
Actual future prices and costs may differ materially from those used in the net present value estimate, and future net
present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10%
discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the
Financial Accounting Standard Board Codification 932, “Extractive Activities-Oil and Gas,” may not be the most appropriate
discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry
in general.
If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase
distributions will be limited.
Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that
result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:
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unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;
unable to obtain financing for these acquisitions on economically acceptable terms; or
outbid by competitors.
If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves
will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level
of cash distributions to our unitholders.
Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to
unitholders.
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One of our growth strategies is to capitalize on opportunistic acquisitions of oil reserves. Even if we make acquisitions
that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash
per unit. Any acquisition involves potential risks, including, among other things:
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the validity of our assumptions about estimated proved reserves, future production, commodity prices, revenues,
operating expenses and costs;
an inability to successfully integrate the assets we acquire;
a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance
acquisitions;
a significant increase in our interest expense or financial leverage if we incur additional debt to finance
acquisitions;
the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity
is inadequate;
the diversion of management’s attention from other business concerns;
an inability to hire, train or retain qualified personnel to manage and operate our growing assets; and
the occurrence of other significant charges, such as the impairment of oil properties, goodwill or other intangible
assets, asset devaluations or restructuring charges.
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and
engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often
inconclusive and subject to various interpretations.
Also, our reviews of properties acquired from third parties (as opposed to the Mid-Con Affiliates) may be incomplete
because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition,
given the time constraints imposed by most sellers. Even a detailed review of the properties owned by third parties and the
records associated with such properties may not reveal existing or potential problems, nor will such a review permit us to
become sufficiently familiar with such properties to assess fully the deficiencies and potential issues associated with such
properties. We may not always be able to inspect every well on properties owned by third parties, and environmental problems,
such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.
Adverse developments in our operating 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 and
Colorado. An adverse development in the oil and natural gas business in these geographic areas could have an impact on our
results of operations and cash available for distribution to our unitholders.
We are primarily dependent upon a small number of customers for our production sales and we may experience a
temporary decline in revenues and production if we lose any of those customers.
Sales of oil and natural gas to Enterprise, Coffeyville, Valero and National accounted for approximately 50%, 23%, 9%
and 8%, respectively, of our sales for the year ended December 31, 2013. Our production is and will continue to be marketed by
our affiliate, Mid-Con Energy Operating. By selling a substantial majority of our current production to a small concentration of
customers we believe that we have obtained and will continue to receive more favorable pricing than would otherwise be
available to us if smaller amounts had been sold to several purchasers based on posted prices. To the extent these significant
customers reduce the volume of oil they purchase from us, we could experience a temporary interruption in sales of, or may
receive a lower price for, our oil production, and our revenues and cash available for distribution could decline which could
adversely affect our ability to make cash distributions to our unitholders at the then-current distribution rate or at all.
In addition, a failure by any of these significant customers, or any purchasers of our production, to perform their payment
obligations to us could have a material adverse effect on our results of operations. To the extent that purchasers of our
production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those
purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that
some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would
recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and
ability to make distributions to our unitholders.
Unitization difficulties may prevent us from developing certain properties or greatly increase the cost of their
development.
Regulation of waterflood unit formation is typically governed by state law. In Oklahoma, where most of our properties are
located, 63% of the leasehold and mineral owners in a proposed unit area must consent to a unitization plan before the
Oklahoma Corporation Commission, the regulatory body which oversees issues related to unitization and well spacing, will
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issue a unitization order. Mid-Con Energy Operating may be required to dedicate significant amounts of time and financial
resources to obtaining consents from other owners and the necessary approvals from the Oklahoma Corporation Commission
and similar regulatory agencies in other states. Obtaining these consents and approvals may also delay our ability to begin
developing our new waterflood projects and may prevent us from developing our properties in the way we desire.
Other owners of mineral rights may object to our waterfloods.
It is difficult to predict the movement of the injection fluids that we use in connection with waterflooding. It is possible
that certain of these fluids may migrate out of our areas of operations and into neighboring properties, including properties
whose mineral rights owners have not consented to participate in our operations. This may result in litigation in which the
owners of these neighboring properties may allege, among other things, a trespass and may seek monetary damages and
possibly injunctive relief, which could delay or even permanently halt our development of certain of our oil properties.
We might be unable to compete effectively with larger companies, which might adversely affect our ability to generate
sufficient revenue to allow us to pay distributions to our unitholders.
The oil and natural gas industry is intensely competitive, and we compete with companies that possess and employ
financial, technical and personnel resources substantially greater than ours. These companies may be able to pay more for
properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources
permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate
and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger
competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and
other products on a regional, national or worldwide basis. In addition, there is substantial competition for investment capital in
the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during
periods of low oil prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our
inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial
condition and results of operations and our ability to make distributions to our unitholders.
Many of our leases are in areas that have been partially depleted or drained by offset wells.
Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. The owners
of leasehold interests lying contiguous or adjacent to or adjoining our interests could take actions, such as drilling additional
wells, that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the
vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing
wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves,
and may inhibit our ability to further exploit and develop our reserves.
We may incur additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to
pay future distributions or execute our business plan.
We may be unable to pay distributions at our current distribution rate without borrowing under our credit facility. If we
use borrowings under our credit facility to pay distributions to our unitholders for an extended period of time rather than to
fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business.
Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to
pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on
our business, financial condition and results of operations. If we borrow to pay distributions to our unitholders during periods
of low commodity prices and commodity prices remain low, we may have to reduce our distribution to our unitholders to avoid
excessive leverage.
Our credit facility has restrictions and financial covenants that may restrict our business and financing activities and
our ability to pay distributions to our unitholders.
Our credit facility restricts, among other things, our ability to incur debt and pay distributions under certain
circumstances, and requires us to comply with customary financial covenants and specified financial ratios. If market or other
economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of
our credit facility that are not cured or waived within specific time periods, a significant portion of our indebtedness may
become immediately due and payable, we will be prohibited from making distributions to our unitholders, and our lenders’
commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these
accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if
we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.
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The total amount we are able to borrow under our credit facility is limited by a borrowing base, which is primarily based
on the estimated value of our oil and natural gas properties and our commodity derivative contracts, as determined by our
lenders in their sole discretion. The borrowing base is subject to redetermination on a semi-annual basis and more frequent
redetermination in certain circumstances. Our lenders increased the borrowing base from $130 million to $150 million in
November 2013. Any substantial or sustained decline in commodity prices would likely lead to a decrease in our borrowing
base upon redetermination, and in such case, we could be required to repay any indebtedness in excess of the borrowing base.
In the future, we may be unable to access sufficient capital under our credit facility as a result of a decrease in our borrowing
base due to a subsequent borrowing base redetermination.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately
insured.
There are a variety of operating risks inherent in the exploration, development and production of our oil and natural gas
properties, such as leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial
losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs,
personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations
and substantial revenue losses. The location of our wells and other facilities near populated areas, including residential areas,
commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.
Insurance against all operational risk is not available to us. We are not fully insured against all risks, including
development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and
environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the
cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable
or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the
future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to
weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. As a result, we
may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and
we cannot be sure the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or
cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance
proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make
distributions to our unitholders.
Our business depends in part on transportation, pipelines and refining facilities owned by others. Any limitation in the
availability of those facilities could interfere with our ability to market our production and could harm our business.
The marketability of our production depends in part on the availability, proximity and capacity of pipelines, tanker trucks
and other transportation methods, and refining facilities owned by third parties. The amount of oil that can be produced and
sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled
maintenance, excessive pressure, physical damage or lack of available capacity on such systems, tanker truck availability and
extreme weather conditions. Also, the shipment of our oil on third party pipelines may be curtailed or delayed if it does not
meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last
from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these
circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or refining facility
capacity could reduce our ability to market our oil production and harm our business. Our access to transportation options and
the prices we receive for our production can also be affected by federal and state regulation, including regulation of oil
production and transportation, and pipeline safety, as well by general economic conditions and changes in supply and demand.
In addition, the third parties on whom we rely for transportation services are subject to complex federal, state, tribal and local
laws that could adversely affect the cost, manner or feasibility of conducting our business.
Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced
demand for the oil and natural gas that we produce.
In December 2009, the Environmental Protection Agency, or the EPA, published its findings that emissions of carbon
dioxide, methane and other greenhouse gases, or GHGs, present a danger to public health and the environment. Based on these
findings, the EPA began adopting and implementing regulations that restrict emissions of GHGs under existing provisions of
the federal Clean Air Act, including requirements to reduce emissions of GHGs from motor vehicles, requirements associated
with certain construction and operating permit reviews for GHG emissions from certain large stationary sources, reporting
requirements for GHG emissions from specified large GHG emission sources, including certain owners and operators of
onshore oil and natural gas production and rules requiring so-called green completions of natural gas wells beginning in 2015.
We are currently monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule. Data
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collected from our initial GHG monitoring activities indicated that we do not exceed the threshold level of GHG emissions
triggering a reporting obligation. To the extent we exceed the applicable regulatory threshold level in the future, we will report
the emissions beginning in the applicable period. Also, Congress has from time to time considered legislation to reduce
emissions of GHGs, and almost one-half of the states, either individually or through multi-state regional initiatives, already
have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations
imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur
significant costs to reduce emissions of GHGs associated with operations or could adversely affect demand for our production.
Rules recently finalized regulating air emissions from oil and natural gas operations could cause us to incur increased
capital expenditures and operating costs.
In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage
operations to regulation under the NSPS and NESHAP programs. The EPA’s final rule includes NSPS standards for
completions of hydraulically fractured wells and establishes specific new requirements for emissions from compressors,
controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The new rules became
effective October 15, 2012; however, a number of the requirements did not take immediate effect. The final rule establishes a
phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first
phase, ending December 31, 2014, owners and operators must either flare their emissions or use emissions reduction
technology called “green completions” technologies already deployed at wells. On or after January 1, 2015, all newly fractured
wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in
over one year beginning on August 16, 2012, which is the date the final rule was published in the Federal Register, while
certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60
days after publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the
EPA’s final rule, as it may require changes to our operations, including the installation of new emissions control equipment.
Our operations are subject to environmental and operational safety laws and regulations that may expose us to
significant costs and liabilities.
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil
development and production activities. These costs and liabilities could arise under a wide range of federal, state, tribal and
local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to
become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of
administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent,
issuance of injunctions to limit or cease operations. In addition, we may experience delays in obtaining or be unable to obtain
required permits, which may delay or interrupt our operations and limit our growth and revenue. Claims for damages to persons
or property from private parties and governmental authorities may result from environmental and other impacts of our
operations.
Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become
liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the
time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen
liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or
increased revenues, our ability to make cash distributions to our unitholders could be adversely affected. For a detailed
discussion please read “Item 1. Business-Environmental Matters and Regulation.”
The derivatives regulation provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act and related
rules could adversely affect on our ability to use derivative contracts to reduce the effect of commodity price, interest rate
and other risks associated with our business.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), which was enacted on July 21,
2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that
participate in that market. Pursuant to the Act, the Commodities Futures Trading Commission (the “CFTC”), the SEC and other
regulators have promulgated and continue to promulgate rules implementing the Act’s derivative regulation provisions. The
CFTC has finalized numerous such rules, including critical rulemakings on the definition of “swap”, “security-based swap”,
“swap dealer” and “major swap participant.” The Act and the CFTC rules will require us, in connection with certain derivatives
activities, to comply with mandatory clearing and exchange-trading requirements (or take steps to qualify for an exemption to
such requirements) with respect to swaps we enter that fall within a class of swaps the CFTC has designed for mandatory
clearing. Although we expect to qualify for the “end-user exception” to the mandatory clearing and exchange-trading
requirements for the swaps we enter to hedge our commercial risks, these mandatory clearing and exchange-trading
requirements apply to other market participants, such as our counterparties (who may be registered as swap dealers), and the
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application of those requirements to such persons may change the cost and availability of the swaps we use to hedge our
commercial risks. As of March 5, 2014, the CFTC had only designated certain classes of interest rate swaps and index credit
default swaps for mandatory clearing, and it is unclear when the CFTC will designate other classes of swaps, such as physical
commodity swaps, for mandatory clearing. New regulations expected to be adopted by the CFTC and banking regulators may
require us to comply with requirements to post margin with our counterparties for uncleared swaps, although these regulations
are not finalized and how the final regulations will affect us is uncertain at this time. In addition, the CFTC recently proposed
new position limits rules that sets limits on the positions in certain core futures and equivalent swaps contracts for or linked to
certain physical commodities that market participants could hold, subject to with exceptions for certain bona fide hedging
transactions intended to hedge certain price risks. The CFTC proposed the new position limits rule after the United States
District Court for the District of Columbia invalidated a position limits rule the CFTC had previously adopted. Other rules also
remain to be finalized by the CFTC, and, as a result, it is not possible at this time to predict with certainty the full effects of the
Act and the related rules on us and the timing of such effects. A rule recently adopted under the Act may also require certain of
the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities. Those
separate entities would be our counterparties in future swaps and may not be as creditworthy as our current counterparties. The
Act and the rules adopted thereunder may significantly increase the cost of entering into and maintaining derivative contracts
(including to comply with swap recordkeeping and reporting requirements and through requirements to post collateral which
could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of
derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts,
and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and the
related rules, our results of operations may become more volatile and our cash flows may be less predictable, which could
adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the
volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity
instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act is to
lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial
position, results of operations, liquidity and cash flows.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used in the completion of unconventional wells in shale
formations as well as tight conventional formations, including many of those that we complete and produce. The hydraulic
fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the
surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions.
However, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel
under the federal Safe Drinking Water Act and has published draft guidance documents related to this newly asserted regulatory
authority. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing
and to require disclosure of the chemicals used in the hydraulic fracturing process. Many states in which we operated have
adopted new rules requiring well operators to publicly disclose certain information regarding hydraulic fracturing operations,
including the chemical composition of any liquids used in the hydraulic fracturing process. Generally, certain proprietary
information may be excluded from an operator’s disclosure. Additionally, some states and local authorities have adopted and
other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. In the event
that new or more stringent federal, state or local legal restrictions are adopted in areas where we operate, we could incur
potentially significant added costs to comply with such requirements, experience delays or curtailment in our development or
production activities.
In addition, there are certain governmental reviews either underway or being proposed that focus on environmental
aspects of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to
review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential
environmental effects of hydraulic fracturing on drinking water and groundwater, and published an updated on December 21,
2012 with final results expected by 2014. Moreover, the EPA announced on October 20, 2011 that it is also launching a study
regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such
wastewater must meet before being transported to a treatment plant. On April 13, 2012, the Department of Interior, the
Department of Energy and the Environmental Protection Agency issued a memorandum outlining a multi-agency collaboration
on unconventional oil and gas research in response to the White House “Blueprint for a Secure Energy Future” and the
recommendations of the Secretary of Energy Advisory Board Subcommittee on Natural Gas. On September 5, 2012, the U.S.
Government Accountability Office issued two reports concerning environmental and health risks and key environmental and
public health requirements related to hydraulic fracturing but did not make any recommendations. More recently there have
been reports linking the injection of produced fluids from hydraulic fracturing to earthquakes. These ongoing or proposed
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studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate
hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.
A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may
affect adversely our financial results.
Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If
any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial
results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational
systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems.
In addition, dependence upon automated systems may further increase the risk operational system flaws, employee tampering
or manipulation of those systems will result in losses that are difficult to detect.
Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our
business. We use computer programs to help run our financial and operations sectors, and this may subject our business to
increased risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a
material adverse effect on our business. In addition, cyber attacks on our customer and employee data may result in a financial
loss and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system
failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise
have an adverse effect on our financial results.
Risks Inherent in an Investment in Us
Our general partner controls us, and the Founders and Yorktown own an approximate 18.8% interest in us. They have
conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the
detriment of us and our unitholders.
Our general partner has control over all decisions related to our operations. Our general partner is owned by the Founders.
As of December 31, 2013, the Founders and Yorktown own an approximate 18.8% interest in us. Although our general partner
has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our
general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. All of the executive
officers and non-independent directors of our general partner are also officers and/or directors of the Mid-Con Affiliates and
will continue to have economic interests in, as well as management and fiduciary duties to, the Mid-Con Affiliates.
Additionally, one of the directors of our general partner is a principal with Yorktown. As a result of these relationships,
conflicts of interest may arise in the future between the Mid-Con Affiliates and Yorktown and their respective affiliates,
including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of
interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common
unitholders. These potential conflicts include, among others:
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Our partnership agreement limits our general partners’ liability, reduces its fiduciary duties and also restricts the
remedies available to our unitholders for actions that, without these limitations, might constitute breaches of
fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest
that might otherwise constitute a breach of fiduciary or other duties under applicable law;
Neither our partnership agreement nor any other agreement requires the Mid-Con Affiliates and Yorktown or their
respective affiliates (other than our general partner) to pursue a business strategy that favors us. The officers and
directors of the Mid-Con Affiliates and Yorktown and their respective affiliates (other than our general partner)
have a fiduciary duty to make these decisions in the best interests of their respective equity holders, which may be
contrary to our interests;
The Mid-Con Affiliates and Yorktown and their affiliates are not limited in their ability to compete with us,
including with respect to future acquisition opportunities, and are under no obligation to offer or sell assets to us;
All of the executive officers of our general partner who provide services to us also devote a significant amount of
time to the Mid-Con Affiliates and are compensated for those services rendered;
Our general partner determines the amount and timing of our development operations and related capital
expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments,
including investment capital expenditures in other businesses with which our general partner is or may become
affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;
We entered into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy
Operating provides management, administrative and operational services to us, and Mid-Con Energy Operating
will also provide these services to the Mid-Con Affiliates;
Our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any
services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
Our general partner intends to limit its liability regarding our contractual and other obligations and, in some
circumstances, is entitled to be indemnified by us;
Our general partner may exercise its limited right to call and purchase common units if it and its affiliates own
more than 80% of the common units;
Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to manage
and operate our business. The management team of Mid-Con Energy Operating, which includes the individuals who
manage us, also provides substantially similar services to the Mid-Con Affiliates, and thus is not solely focused on our
business.
Neither we nor our general partner have any employees, and we rely solely on Mid-Con Energy Operating to provide
management, administrative and operational services to us. Mid-Con Energy Operating provides substantially similar services
and personnel to the Mid-Con Affiliates and, as a result, may not have sufficient human, technical and other resources to
provide those services at a level that it would be able to provide to us if it did not provide similar services to these other
entities. Additionally, Mid-Con Energy Operating may make internal decisions on how to allocate its available resources and
expertise that may not always be in our best interest compared to those of the Mid-Con Affiliates or other affiliates of our
general partner. There is no requirement that Mid-Con Energy Operating favor us over these other entities in providing its
services. If the employees of Mid-Con Energy Operating do not devote sufficient attention to the management and operation of
our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur
debt.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs
to increase. In addition, as with other yield-oriented securities, our unit price is impacted by the level of our cash distributions
to our unitholders and implied distribution yield. This implied distribution yield is often used by investors to compare and rank
similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive
or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate
environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt.
Public unitholders do not have a priority right to receive distributions and are not entitled to receive any payments of
arrearages.
Unlike many publicly traded partnerships, we do not have any incentive distribution rights or subordinated units. Because
there are no subordinated units, our public unitholders are not senior in payment of distributions over any other parties,
including the Founders or Yorktown. In addition, if the amount of any future distribution is less than the current quarterly
distribution rate, public unitholders will not have any right to receive any payments of arrearages in future periods.
Units held by persons who our general partner determines are not eligible holders will be subject to redemption.
To comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have
adopted certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder
means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof,
Eligible Holder means:
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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 United States citizens, such as a partnership or limited liability company, organized under the
laws of the United States or of any state thereof, but only if such association does not have any direct or indirect
foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the
United States or of any state thereof; or
a limited partner whose nationality, citizenship or other related status would not, in the determination of our
general partner, create a substantial risk of cancellation or forfeiture of any property in which we or our subsidiary
has an interest.
Onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock
ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders
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who are not persons or entities who meet the requirements to be an Eligible Holder run the risk of having their common units
redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note,
as determined by our general partner.
Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors,
which could reduce the price at which our common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no
right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general
partner, including the independent directors, is chosen entirely by the Founders, as a result of their ownership of our general
partner, and not by our unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders
to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of
these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a
takeover premium in the trading price
Even if our unitholders are dissatisfied, it would be difficult to remove our general partner without its consent.
Currently, it would be difficult for the public unitholders to remove our general partner without its consent because
affiliates of our general partner and Yorktown own sufficient units to make it difficult to remove our general partner. The vote
of the holders of at least 66 2/3% of all outstanding units is required to remove our general partner. As of December 31, 2013,
the Founders and Yorktown owned approximately 18.8% of our outstanding limited partner units, which will enable those
holders, collectively, to make it difficult to remove our general partner.
Control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer interest to a third party in a merger or in a sale of all or substantially all of its assets
without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the Founders
from transferring all or a portion of their ownership interests in our general partner to a third party. The new owner of our
general partner would then be in a position to replace the board of directors and officers of our general partner with their own
choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned
with the interests of our unitholders.
We may not make cash distributions during periods when we record net income.
The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including
cash from reserves established by our general partner and borrowings, and not solely on profitability, which will be affected by
non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and
may not make cash distributions to our unitholders during periods when we record net income.
We may issue an unlimited number of additional units, including units that are senior to the common units, without
unitholder approval, which would dilute unitholders’ ownership interests.
Our partnership agreement does not limit the number of additional common units that we may issue at any time without
the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in
right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or
senior rank will have the following effects:
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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 limited voting rights of unitholders, other than Yorktown, our general partner
and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to
influence the manner or direction of management.
Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a
person, entity or group owning 20% or more of any class of common units then outstanding, other than Yorktown, our general
partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of
directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the
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ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting
unitholders’ ability to influence the manner or direction of management.
Sales of our common units by the selling unitholders may cause our price to decline.
As of December 31, 2013, the Founders and Yorktown own 3,638,555 common units or approximately 18.8% of our
limited partner interests. Sales of these units or of other substantial amounts of our common units in the public market, or the
perception that these sales may occur, could cause the market price of our common units to decline. Sales of such units could
also impair our ability to raise capital through the sale of additional common units.
Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those
contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is
organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders
of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other
states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:
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a court or government agency determined that we were conducting business in a state but had not complied with
that particular state’s partnership statute; or
a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some
amendments to our partnership agreement or to take other actions under our partnership agreement constitute
“control” of our business.
Our unitholders may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under
Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the
distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their
partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a
distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution,
limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be
liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is
liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of
common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from
our partnership agreement.
Our partnership agreement requires that we distribute all of our available cash (as defined in our partnership
agreement), which could limit our ability to grow our reserves and production and make acquisitions.
Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be
dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A
number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such
financings, including:
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general economic and market conditions, including interest rates prevailing at the time we desire to issue securities
or borrow funds;
conditions in the oil and gas industry;
the market price of, and demand for, our common units;
our results of operations and financial condition; and
prices for oil and natural gas.
In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that
reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any
acquisitions, or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we
will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or in
our credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of
additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense,
which, in turn, may impact the available cash that we have to distribute to our unitholders.
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Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue
Service (“IRS”) were to treat us as a corporation, then our cash available for distribution to our unitholders would be
substantially reduced.
The anticipated after-tax economic benefit of an investment in the units depends largely on our being treated as a
partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or
any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based on
our current operations that we are so treated, the IRS could disagree with the positions we take, or a change in our business (or
a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to
taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable
income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates.
Distributions to unitholders would generally be taxed again as corporate distributions which would be taxable as dividends for
U.S. federal income tax purposes to the extent paid out of our current or accumulated earnings and profits as determined for
U.S. federal income tax purposes, and no income, gains, losses or deductions would flow through to unitholders. Because a tax
would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced.
Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return
to our unitholders, likely causing a substantial reduction in the value of our units.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our
cash available for distribution to our unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread
state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through
the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the
cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative,
judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may
be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time the Obama
Administration and members of the U.S. Congress propose and consider substantive changes to the existing federal income tax
laws that would affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof
may or may not be applied retroactively. Although we are unable to predict whether any of these changes, or other proposals,
will ultimately be enacted, any such changes could negatively impact the value of an investment in our units.
Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and
production may be eliminated as a result of future legislation.
The Obama Administration’s budget proposal for fiscal year 2014 includes proposals that would, among other things,
eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production
companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural
gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of
the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological
and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such
changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in
U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil
and natural gas exploration and development, and any such change could increase the taxable income allocable to our
unitholders and negatively impact the value of an investment in our units.
If the IRS contests any of the federal income tax positions we take, the market for our units may be adversely affected,
and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for
federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we
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take. It may be necessary to resort to administrative or court proceedings to sustain some or all our counsel’s conclusions or the
positions we take. A court may not agree with some or all our counsel’s conclusions or of the positions we take. Any contest
with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the
costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will
reduce our cash available for distribution.
Our unitholders are required to pay taxes on their share of our taxable income even if they do not receive any cash
distributions from us.
Because our unitholders are treated as partners to whom we will allocate taxable income, which could be different in
amount than the cash we distribute, our unitholders are required to pay any federal income taxes and, in some cases, state and
local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may
not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that
results from that income.
Tax gain or loss on the disposition of our units could be more or less than expected.
If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized
and their adjusted tax basis in their units. Because prior distributions in excess of their allocable share of our total net taxable
income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they
sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units,
even if the price they receive is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or
not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion,
amortization and Intangible Drilling Costs (“IDC”) deduction recapture. In addition, because the amount realized may include a
unitholder’s share of our nonrecourse liabilities, and they may incur a tax liability in excess of the amount of cash they receive
from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax
consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts,
(“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to
organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business
taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the
highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax
on their share of our taxable income. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult
their tax advisor before investing in our units.
We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS
may challenge this treatment, which could adversely affect the value of the units.
Because we cannot match transferors and transferees of units and because of other reasons, we will adopt depreciation,
depletion and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS
challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect
the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of
our units or result in audits of and adjustments to a unitholder’s tax return.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month
based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and
deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month
based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and although the
United States Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention,
such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS
were to challenge our proration method or new Treasury Regulations were issued, we may be required to change our method of
allocating items of income, gain, loss and deduction among our unitholders.
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A unitholder whose units are loaned to a “short seller” to affect a short sale of units may be considered as having
disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having
disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those units
during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover,
during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not
be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as
ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a
short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account
agreements to prohibit their brokers from borrowing their units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in
the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50%
or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the
50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence
as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year
for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if
special relief from the IRS is not available) for one fiscal year and could result in a significant deferral of depreciation
deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a
fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable
income or loss being includable in such unitholder’s taxable income for the year of termination. A technical termination would
not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new
partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties
if we are unable to determine that a technical termination occurred. The IRS has announced a relief procedure whereby if a
publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the
partnership will only have to provide one Schedule K-1 to unitholders for the tax year in which the termination occurs.
As a result of investing in our units, our unitholders may become subject to state and local taxes and return filing
requirements in jurisdictions where we operate or own or acquire property.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local
taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in
which we conduct business or own property now or in the future even if such unitholders do not live in those jurisdictions. Our
unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all
of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements.
We own property and conduct business in Oklahoma and Colorado, each of which currently imposes a personal income tax on
individuals. These states also impose an income tax on corporations and other entities. As we make acquisitions or expand our
business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property
or conduct business in other states or foreign countries in the future. It is a unitholder’s responsibility to file all U.S. federal,
state and local tax returns.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
PROPERTIES
Information regarding our properties is contained in “Item 1. Business —Our Areas of Operation and —Our Oil and
Natural Gas Data” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —
Results of Operations” contained herein.
38
ITEM 3.
LEGAL PROCEEDINGS
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal
course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any
significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various
environmental protection statutes to which we are subject. No amounts have been accrued at December 31, 2013.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
39
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common units are traded on the NASDAQ Global Select Market under the symbol “MCEP”. At the close of business
on March 5, 2014, based upon information received from our transfer agent and brokers and nominees, we had 84 common
unitholders of record. This number does not include owners for whom common units may be held in “street” names. The daily
high and low sales prices per common unit for the period from January 1, 2013 through December 31, 2013 were $27.05 and
$18.94, respectively. The following table sets forth the range of the daily high and low sale prices per common unit and cash
distributions to common unitholders for 2012 and 2013.
2012:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2013:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Price Range
Cash Distribution
High
Low
per Common Unit (1)
$
25.18
$
18.25
$
24.66
24.12
23.00
17.87
20.31
17.40
$
23.95
$
18.94
$
26.50
25.28
27.05
21.04
21.34
21.50
0.475
0.475
0.485
0.495
0.505
0.515
0.515
0.515 (1)
(1)
On January 22, 2014, the board of directors of our general partner declared a quarterly cash distribution for the
fourth quarter 2013 of $0.515 per common unit. The distribution was paid on February 14, 2014.
Cash Distributions to Unitholders
We intend to continue to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to
the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition
and other factors. Our credit agreement prohibits us from making cash distributions if any potential default or event of default,
as defined in the credit agreement, occurs or would result from the cash distribution.
Cash Distribution Policy
Our partnership agreement requires that, within 45 days after the end of each quarter we distribute all of our available
cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. We will distribute
approximately 98.2% of our available cash to our common unitholders, pro rata, and approximately 1.8% to our general
partner. Our general partner is not entitled to any incentive distributions, and we do not have any subordinated units.
Definition of Available Cash
Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:
•
•
•
•
less, the amount of cash reserves established by our general partner at the date of determination of available cash
for the quarter to:
provide for the proper conduct of our business (including reserves for future capital expenditures, working capital
and operating expenses) subsequent to that quarter;
comply with applicable law, any of our loan agreements, security agreements, mortgages debt instruments or other
agreements; or
provide funds for distributions to our unitholders (including our general partner) for any one or more of the next
four quarters;
40
•
plus, if our general partner so determines, all or a portion of cash or cash equivalents on hand on the date of
determination of available cash for the quarter.
Securities Authorized for Issuance under Equity Compensation Plans
See “Item 11. Executive Compensation—Compensation Discussion and Analysis—Long-Term Incentive Program” for
information regarding our equity compensation plans as of December 31, 2013.
Unregistered Sales of Equity Securities
None.
Issuer Purchases of Equity Securities
None.
ITEM 6.
SELECTED FINANCIAL DATA
The selected financial data for the years ended December 31, 2013, 2012, 2011, 2010 and six months ended December 31,
2009, are derived from our audited financial statements. The selected financial data for the year ended June 30, 2009 is derived
from the audited financial statements of our predecessor. The selected financial data should be read in conjunction with “Item
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements
and Supplementary Data,” both contained herein.
41
The following table shows selected financial data for the periods and as of the dates indicated (in thousands except
number of units):
Mid-Con Energy Partners, LP
Year Ended December 31,
Mid-Con
Energy
Corporation
Year Ended
June 30,
Six Months
Ended
December 31,
2013
2012
2011
2010
2009
2009
Revenues:
Oil sales
Natural gas sales
Net settlements on derivatives
Gain (loss) on unsettled derivatives, net
Total revenues
Operating costs and expenses:
Lease operating expenses
Oil and gas production taxes
Impairment of proved oil and gas properties
Dry holes and abandonments of unproved properties
Depreciation, depletion and amortization
Accretion of discount on asset retirement obligations
General and administrative
Total operating costs and expenses
Income (loss) from operations
Other income (expense):
Interest income and other
Interest expense
Gain on sale of assets
Other revenue and expenses, net
Income tax expense- current
Income tax benefit (expense) deferred
Total other income (expense)
Net income (loss)
Computation of net income (loss) per limited partner unit:
General partners’ interest in net income (loss)
Limited partners’ interest in net income (loss)
Net income (loss) per limited partner unit:
Basic
Diluted
$
85,080
$
60,887
$
36,813
$
16,853
$
5,729
$
656
288
(5,963)
674
3,710
2,004
1,218
(2,157)
3,437
1,418
(90)
(707)
743
(350)
(147)
$
80,061
$
67,275
$
39,311
$
17,474
$
5,975
$
6,237
822
1,886
1,418
5,851
127
1,376
2,431
269
9,208
—
2,552
58
704
$
$
17,717
$
(243) $
15,222
(9,247)
$
$
16,366
10,948
3,817
1,578
—
14,421
173
12,244
48,599
31,462
$
$
1,965
1,296
—
10,324
126
11,000
35,659
31,616
$
$
9
10
(3,282)
(1,764)
—
—
—
—
—
—
—
—
8,491
1,869
—
813
7,160
78
3,767
22,178
17,133
216
(578)
1,621
576
—
—
(3,273) $
(1,754) $
1,835
28,189
518
27,671
1.44
1.44
$
$
$
$
$
29,862
584
29,278
1.62
1.62
$
$
$
$
$
18,968
379
18,589
1.05
1.05
$
$
$
$
$
$
$
$
$
$
$
$
$
$
218
(98)
354
847
—
—
1,321
1,078
22
1,056
0.06
0.06
$
$
$
$
$
$
Weighted average limited partner units outstanding:
Common limited partner units (basic)
Common limited partner units (diluted)
19,234
19,249
18,049
18,049
17,640
17,640
17,640
17,640
10,246
2,172
(669)
1,679
13,428
5,369
631
—
—
2,293
78
2,274
10,645
2,783
119
(93)
—
298
(625)
502
201
2,984
$
$
35
(2)
—
118
—
—
151
(9,096)
(182)
(8,914)
(0.51)
(0.51)
17,640
17,640
2,420
40,496
337
36,779
Balance Sheet Data:
Working capital
Total assets
Long-term debt
Total equity
Other Financial Data:
Adjusted EBITDA
$
1,435
$
6,254
$
2,361
$
(1,256) $
190,083
112,000
66,788
158,590
78,000
72,181
96,611
45,000
43,349
56,867
5,513
43,072
$
59,973
$
47,681
$
23,994
$
10,593
$
2,836
42
Non-GAAP Financial Measures
We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our calculation of
Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash from operating activities, which are
the GAAP financial measurements most directly comparable to Adjusted EBITDA. We define Adjusted EBITDA as net income
(loss):
•
Plus:
•
•
•
•
•
•
•
•
interest expense;
depreciation, depletion and amortization;
accretion of discount on asset retirement obligations;
losses on unsettled derivatives, net;
impairment expenses;
dry hole costs and abandonments of unproved properties;
non-cash equity-based compensation; and
loss on sale of assets;
•
Less:
•
•
•
interest income;
gains on unsettled derivatives, net; and
gain on sale of assets.
Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from
operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. We believe
Adjusted EBITDA is useful to investors because it is used by our management, by external users of financial statements, such
as industry analysts, investors, lenders, rating agencies and others, to assess the cash flow generated by our assets, without
regard to financing methods, capital structure or historical cost basis and our ability to incur and service debt and fund capital
expenditures. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all
companies may not calculate Adjusted EBITDA in the same manner. Furthermore, Adjusted EBITDA should not be viewed as
indicative of the actual amount of cash that is available for distributions or that is planned to be distributed for a given period
nor do they equate to available cash as defined in our partnership agreement.
The following table presents our reconciliation of Adjusted EBITDA to Net income (loss), for each of the periods
indicated. The table below further presents a reconciliation of Adjusted EBITDA to cash flow from operating activities, our
most directly comparable GAAP financial measure, for each of the periods indicated.
43
Mid-Con Energy Partners, LP
Year Ended December 31,
2013
2012
2011
2010
(in thousands)
Six Months
Ended
December 31,
2009
Mid-Con
Energy
Corporation
Year Ended
June 30,
2009
(in thousands)
$
$ 28,189
—
—
3,282
14,421
173
5,963
1,578
—
—
6,376
(9)
$ 29,862
—
—
1,764
10,324
126
(2,004)
1,296
—
—
6,323
(10)
$ 18,968
—
—
578
7,160
78
(3,437)
—
813
(1,621)
1,671
(216)
$ 1,078
—
—
98
5,851
127
707
1,886
1,418
(354)
—
(218)
$
(9,096)
—
—
2
2,552
58
147
9,208
—
—
—
(35)
2,984
(502)
625
93
2,293
78
(1,679)
—
—
—
—
(119)
$ 59,973
$ 47,681
$ 23,994
$ 10,593
$
2,836
$
3,773
Net income (loss)
Income tax (benefit) expense- deferred
Income tax expense - current
Interest expense
Depreciation, depletion and amortization
Accretion of discount on asset retirement obligations
Loss (Gain) on unsettled derivatives, net
Impairment of oil and gas properties
Dry hole costs
Gain on sales of assets
Non-cash equity-based compensation
Interest income
Adjusted EBITDA
A reconciliation of Adjusted EBITDA to net cash provided by operating activities, our most directly comparable GAAP
financial measure, for each of the periods indicated, is presented below:
Net cash provided by operating activities
Amortization of debt placement fees
Change in working capital
Income tax expense - current
Interest expense
Interest income
Adjusted EBITDA
Mid-Con
Energy
Corporation
Year Ended
June 30,
2009
(in thousands)
$
10,935
—
(7,761)
625
93
(119)
3,773
Mid-Con Energy Partners, LP
Year Ended December 31,
Six Months
Ended
December 31,
2013
2012
2011
2010
2009
(in thousands)
$
56,634
$
47,717
$
24,113
$
11,798
$
(168)
234
—
3,282
(9)
(131)
(1,659)
—
1,764
(10)
—
(481)
—
578
(216)
—
(1,085)
—
98
(218)
965
—
1,904
—
2
(35)
$
59,973
$
47,681
$
23,994
$
10,593
$
2,836
$
44
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in
conjunction with “Item 8. Financial Statements and Supplementary Data” contained herein.
Overview
Mid-Con Energy Partners, LP (“we,” “our,” “us,” the “Partnership”) is a publicly held Delaware limited partnership
formed in December 2011, that engages in the operation, acquisition, exploitation and development of producing oil and natural
gas properties in North America, with a focus on the Mid-Continent region of the United States. Our common units are traded
on the NASDAQ Global Select Market under the symbol “MCEP”. Our general partner is Mid-Con Energy GP, LLC, a
Delaware limited liability company.
Our properties are located in the Mid-Continent region of the United States in three core areas: Southern Oklahoma,
Northeastern Oklahoma and parts of Oklahoma and Colorado within the Hugoton Basin. Our properties primarily consist of
mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low production decline
rates.
As of December 31, 2013, our total estimated proved reserves were approximately 13.9 MMBoe, of which approximately
98% were oil and 76% were proved developed, both on a Boe basis. As of December 31, 2013, we operated 99% of our
properties through our affiliate, Mid-Con Energy Operating and 99% of our properties were being produced under waterflood,
in each instance on a Boe basis. Our average net production for the month ended December 31, 2013 was approximately
2,496 Boe per day and our total estimated proved reserves had an average reserve-to-production ratio of approximately
15 years.
We are an “emerging growth company” as defined in Section 101 of the Jumpstart Our Business Startups Act of 2012, or
the JOBS Act.
Developments in 2013
In May 2013 we acquired additional working interest in our Cushing properties located in the Northeastern Oklahoma
core area and in certain Southern Oklahoma units for approximately $27.4 million.
During 2013, we drilled 22 gross producing wells, 8 gross injector wells, 1 water supply well and converted 10 gross
producing wells to injection wells.
Other
During November 2013, the borrowing base under our credit facility was increased from $130.0 million to $150.0 million
and Scotiabank was added to the lender group. Effective with this increase, the maturity terms of our credit facility were
extended to November 2018. No other material terms of the original credit agreement were amended.
Business Environment
The markets for oil, natural gas, and NGLs have been volatile historically and may continue to be volatile in the future,
which means that the price of oil can fluctuate widely. Sustained periods of low prices for oil could materially and adversely
affect our financial position, our results of operations, the quantities of oil reserves that we can economically produce and our
access to capital.
Our hedging strategy is to enter into various commodity derivative contracts intended to achieve more predictable cash
flows and to reduce exposure to fluctuations in the price of oil. Our hedging program’s objective is to protect our ability to
make current distributions, and to allow us to be better positioned to increase our quarterly distributions over time, while
retaining some ability to participate in upward moves in oil prices. We use a phased approach, looking approximately 36
months forward while targeting a higher amount of hedges in the near 12 months.
Our business faces the challenge of natural production declines. As initial reservoir pressures are depleted, oil production
from a given well or formation decreases. Although our waterflood operations tend to restore reservoir pressure and production,
once a waterflood is fully effected, production, once again, begins to decline. Our future growth will depend on our ability to
continue to add reserves in excess of our production. We plan to maintain our focus on adding reserves primarily through
improving the economics of producing oil from our existing fields and, secondarily, through acquisitions of additional proved
reserves. Our ability to add reserves through exploitation projects and acquisitions is dependent upon many factors, including
45
our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel, and successfully identify
and close acquisitions.
We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is
appropriate for long-term operations. Our future cash flows from operations are impacted by our ability to manage our overall
cost structure.
How We Evaluate Our Operations
Our primary business objective is to manage our oil and natural gas properties for the purpose of generating stable cash
flows, which will provide stability and, over time, growth of distributions to our unitholders. The amount of cash that we can
distribute to our unitholders depends principally on the cash we generate from our operations, which will fluctuate from quarter
to quarter based on, among other factors:
•
•
•
•
the amount of oil and natural gas we produce;
the prices at which we sell our oil and natural gas production;
our ability to hedge commodity prices; and
the level of our operating and administrative costs.
We use a variety of financial and operational metrics to assess the performance of our oil 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;
Lease operating expenses; and
Adjusted EBITDA.
Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial
statements, such as industry analysts, investors, lenders, rating agencies and others, to assess:
•
•
the cash flow generated by our assets, without regard to financing methods, capital structure or historical cost
basis; and
our ability to incur and service debt and fund capital expenditures.
In addition, management uses Adjusted EBITDA to evaluate actual potential cash flow available to pay distributions to
our unitholders, develop existing reserves or acquire additional oil properties.
Critical Accounting Policies and Estimates
Oil and Natural Gas Reserves
Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological
analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current
operating and economic parameters. The estimates of our proved reserves as of December 31, 2013 are based on reserve reports
prepared by our reservoir engineering staff and audited by Cawley, Gillespie & Associates, Inc. The estimates of reserves
conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the
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 also a function of many assumptions, all of which could deviate
significantly from actual results. For example, when the price of oil and natural gas increases, the economic life of our
properties is extended, thus increasing estimated proved reserve quantities and making certain projects economically viable.
Likewise, if oil and natural gas prices decrease, the properties economic life is reduced and certain projects may become
uneconomic, reducing estimated proved reserve quantities. Oil and natural gas price volatility adds to the uncertainty of our
reserve quantity estimates. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and
NGLs 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 and Supplementary Data”
and see also Item 1. “Business.”
46
Successful Efforts Method of Accounting
We account for oil and natural gas properties in accordance with the successful efforts method. In accordance with this
method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis
over the remaining life of the proved reserves and proved developed reserves, respectively.
We evaluate the impairment of our proved oil and natural gas properties on a field-by-field basis whenever events or
changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are
reduced to fair value when the expected undiscounted future cash flow is less than net book value. The fair values of proved
properties are measured using valuation techniques consistent with the income approach, converting future cash flow to a
single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of:
(i) reserves; (ii) future operating and developmental costs; (iii) future commodity prices; and (iv) a market-based weighted
average cost of capital rate. The underlying commodity prices embedded in our estimated cash flow is the product of a process
that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other
factors that management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a
part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation and depletion unless doing so
significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or
losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to
maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are
capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining
life of the related proved developed reserves.
Impairment of Oil and Natural Gas Properties
We review our long-lived assets to be held and used, including proved oil and gas properties accounted for under the
successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may
not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as
the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and possible
oil and gas reserves over the economic life of the reserves based on our expectations of future oil and gas prices and costs. We
review our oil and gas properties by amortization base (field) or by individual well for those wells not constituting part of an
amortization base.
Asset Retirement Obligations
The initial estimated asset retirement obligation (“ARO”) associated with oil and natural gas properties is recognized as a
liability, with a corresponding increase in the carrying value of oil and natural gas properties. Amortization expense is
recognized over the estimated productive life of the related assets. If the fair value of the estimated ARO changes, an
adjustment is recorded to both the liability and the carrying value of the property. Revisions in estimated liabilities can result
from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling AROs.
Revenue Recognition
Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as
applicable. Virtually all of our contracts’ pricing provisions are tied to a market index with certain adjustments based on, among
other factors, the quality of oil, location differentials and prevailing supply and demand conditions, so that prices fluctuate to
remain competitive with other available suppliers.
Derivative Contracts and Hedging Activities
Current accounting rules require that all derivative contracts, other than those that meet specific exclusions, be recorded at
fair value. Quoted market prices 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 of derivatives with similar characteristics or on other valuation techniques. We
use certain pricing models to determine the fair value of our derivative financial instruments. Inputs to the pricing models
include publicly available prices from a compilation of data gathered from third parties and brokers. We compare our estimates
of the fair values of our derivative financial instruments with those provided by our counterparties. There have been no
significant differences.
47
We recognize all of our derivative contracts as either assets or liabilities at fair value. The accounting for changes in the
fair value (i.e., gains or losses) of a derivative contract depends on whether it has been designated and qualifies as part of a
hedging relationship, and further, on the type of hedging relationship. For those derivative contracts that are designated and
qualify as hedging instruments, we designated the hedging instrument, based on the exposure being hedged, as either a fair
value hedge or a cash flow hedge. For derivative contracts not designated as hedging instruments, the gain or loss is recognized
in current earnings during the period of change. None of our derivatives were designated as a hedging instrument during the
twelve months ended December 31, 2013, 2012 and 2011.
48
Results of Operations
The table below summarizes certain of the results of operations and period-to-period comparisons for the periods
indicated (in thousands).
Revenues:
Oil sales
Natural gas sales
Net settlements on derivatives
Gain (loss) on unsettled derivatives, net
Total revenues
Operating costs and expenses:
Lease operating expenses
Oil and gas production taxes
Impairment of proved oil and gas properties
Dry holes and abandonments of unproved properties
Depreciation, depletion and amortization (1)
General and administrative (2)
Interest expense
Production: (Unaudited)
Oil (MBbls)
Natural gas (MMcf)
Total (MBoe)
Average net production (Boe/d)
Average sales price: (Unaudited)
Oil (per Bbl):
Sales price
Effect of net settlements on commodity derivative instruments
Realized price after net settlement of derivatives
Natural gas (per Mcf):
Sales price (3)
Average unit costs per Boe: (Unaudited)
Lease operating expenses
Oil and gas production taxes
Depreciation, depletion and amortization
General and administrative expenses
Mid-Con Energy Partners, LP
Year Ended December 31,
2013
2012
2011
$
$
$
$
$
$
$
$
$
$
$
85,080
$
60,887
$
656
288
(5,963)
80,061
16,366
3,817
1,578
—
14,421
12,244
3,282
907
128
928
2,542
93.80
0.32
94.12
5.13
17.64
4.11
15.54
13.19
$
$
$
$
$
$
$
$
$
$
674
3,710
2,004
67,275
10,948
1,965
1,296
—
10,324
11,000
1,764
678
122
698
1,907
89.80
5.47
95.27
5.52
15.68
2.82
14.79
15.76
$
$
$
$
$
$
$
$
$
$
36,813
1,218
(2,157)
3,437
39,311
8,491
1,869
—
813
6,795
3,767
578
407
164
434
1,191
90.45
(5.30)
85.15
7.43
19.56
4.31
15.66
8.68
(1)
(2)
(3)
Depreciation, depletion and amortization expenses for this table only represent the depletion expense for the producing
properties.
General and administrative expenses include non-cash equity-based compensation of $6.4 million, $6.3 million, and $1.7
million for the years ended December 31, 2013, 2012 and 2011, respectively.
Natural gas sales price per Mcf includes the sale of natural gas liquids.
49
Factors Affecting the Comparability of the Historical Financial Results
The comparability of our results of operations among the periods presented is impacted by:
•
•
•
•
•
•
•
•
The drilling of 48 wells in 2011, and 39 wells in 2012 and 31 wells in 2013 on our properties;
Our sale to the Mid-Con Affiliates on June 30, 2011 of certain properties representing less than 1% of our proved
reserves by value, as calculated using the standardized measure, as of September 30, 2011, and certain subsidiaries
that do not own oil and natural gas reserves, including Mid-Con Energy Operating, to the Mid-Con Affiliates for
aggregate consideration of $7.5 million;
Our acquisition of the War Party I and II Units for a purchase price of $7.2 million in June 2011;
Our acquisition in December 2011 of additional working interest in the Cushing Field for $6.0 million;
Our acquisition in June 2012 of properties in Northeastern Oklahoma and additional working interests in Southern
Oklahoma for $16.4 million;
Our acquisition in October 2012 of additional working interests in the War Party I and II Units for $3.7 million;
Our acquisition in November 2012 of the Clawson Ranch Waterflood Unit for $28.9 million;
Our acquisition in May 2013 of additional working interests in our Cushing properties located in the Northeastern
Oklahoma core area and certain Southern Oklahoma units for $27.4 million.
As a result of the factors listed above, historical results of operations and period-to-period comparisons of these results
and certain financial data may not be comparable or indicative of future results.
Year Ended December 31, 2013 Compared with Year Ended December 31, 2012.
Net income was approximately $28.2 million for the year ended December 31, 2013 compared to approximately $29.9
million for the year ended December 31, 2012, a decrease of approximately $1.7 million. The change was attributable to an
increase in oil sales offset by the unfavorable net effect of our derivatives, an increase in operating expenses, depreciation,
general and administrative expenses and interest expense.
Sales Revenues. Revenues from oil and natural gas sales for the year ended December 31, 2013 were approximately $85.7
million as compared to approximately $61.6 million for the year ended December 31, 2012. The increase in revenues was
primarily due to an increase in daily oil production which includes incremental volumes from acquisitions of properties in the
later half of 2012 and additional working interests in 2013.
On average, our production volumes for the year ended December 31, 2013 were approximately 928 MBoe, or
approximately 2,542 Boe per day. In comparison, our total production volumes for the year ended December 31, 2012 were
approximately 698 MBoe, or approximately 1,907 Boe per day on average. The increase in production volumes was primarily
due to the acquisition of additional working interests in our existing properties, waterflood response from injection and our
drilling programs in the our core areas. Also, the increase in production for the year ended December 31, 2013 reflects the
favorable impact from various acquisitions of oil properties and additional working interests during 2012 and 2013. Our
average sales price per barrel of oil, excluding commodity derivative contracts, for the year ended December 31, 2013 was
$93.80, compared with $89.80 for the year ended December 31, 2012.
Effects of Commodity Derivative Contracts. We utilize NYMEX contracts to hedge against changes in commodity prices.
We use certain pricing models to determine the fair value of our derivative contracts. Inputs to the pricing models include
market quotes and pricing analysis. See Note 5, Note 6 and Item 7A. "Quantitative and Qualitative Disclosures About Market
Risk," for additional information about our commodity derivatives. Due to the period change in the mark-to-market value of
these contracts, we recorded a net loss from our commodity hedging program for the year ended December 31, 2013 of
approximately $5.7 million, which was composed of a non-cash loss on unsettled derivative contracts of approximately $6.0
million and a gain of approximately $0.3 million on net cash settlements of derivative contracts. For the year ended
December 31, 2012, we recorded a net gain from our commodity hedging program of approximately $5.7 million, which was
composed of a gain of approximately $3.7 million on net cash settlements of derivative contracts and a non-cash gain of
approximately $2.0 million on unsettled derivative contracts.
Lease Operating Expenses. Our lease operating expenses were approximately $16.4 million for the year ended
December 31, 2013, or $17.64 per Boe, compared to approximately $10.9 million for the year ended December 31, 2012, or
approximately $15.68 per Boe. The increase in total lease operating expenses for the year ended December 31, 2013 primarily
reflects increased oil field service costs and electricity costs resulting from the additional number of producing wells in 2013
and the additional oil properties and working interest acquired during 2012 and 2013. In 2013, the increase in average costs per
50
Boe was primarily due to the higher costs of operations in our Hugoton Basin and Northeastern Oklahoma areas from
acquisitions in October 2012 and May 2013, respectively, and due to workovers and one-time well servicing costs in both
areas. Ad valorem taxes are also reflected in lease operating expenses and the taxes are levied on our properties in Colorado
and are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative
contracts, and a percentage of production equipment value.
Production Taxes. Production taxes are calculated as a percentage of our oil and natural gas revenues, excluding the
effects of our commodity derivative contracts. Our production taxes were approximately $3.8 million for the year ended
December 31, 2013, or approximately $4.11 per Boe for an effective tax rate of approximately 4.5%, compared to
approximately $2.0 million for the year ended December 31, 2012, or approximately $2.82 per Boe for an effective tax rate of
approximately 3.2%. The increase in production taxes during 2013 was directly related to higher oil and gas revenues driven
by increased production and higher oil prices. The per Boe increase in production taxes compared to 2012 was primarily due to
(i) increase in oil and gas revenues for 2013, and (ii) receipt of a prior period production tax credit adjustment of $0.5 million
received in 2012 for one of our Southern Oklahoma units. The adjustment was due to the Enhanced Recovery Project Gross
Production Tax Exemption in Oklahoma through which a portion of our wells receive a reduced tax rate. The State of
Oklahoma, where most of our properties are located, currently imposes a production tax of 7.2% for oil and natural gas
properties and an excise tax of 0.095%.
Impairment Expense. Our impairment expense was approximately $1.6 million and $1.3 million for the year ended
December 31, 2013 and 2012, respectively. We review our long-lived assets to be held and used, including proved oil and
natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be
recoverable. If the carrying amount exceeds the property’s estimated fair value, we adjust the carrying amount of the property
to fair value through a charge to impairment expense. As a result of declines in reserve estimates, during the year ended
December 31, 2013, we recorded approximately a $1.6 million non-cash impairment charge within our miscellaneous core area
properties. During the year ended December 31, 2012 we recorded approximately a $1.1 million and $0.2 million non-cash
impairment charge within our miscellaneous core area and our Southern Oklahoma core areas, respectively.
Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses on producing
properties for the year ended December 31, 2013 were approximately $14.4 million, or approximately $15.54 per Boe
produced, compared to approximately $10.3 million, or approximately $14.79 per Boe produced, for the year ended
December 31, 2012. The increase in depreciation, depletion and amortization expenses was primarily due to the increase in
total asset value of the oil and gas properties from our drilling program and the acquisitions of properties and additional
working interests in our Hugoton Basin, Southern and Northeastern Oklahoma core areas during 2012 and 2013.
General and Administrative Expenses. Our general and administrative expenses were approximately $12.2 million for the
year ended December 31, 2013, or approximately $13.19 per Boe produced compared to approximately $11.0 million for the
year ended December 31, 2012 or approximately $15.76 per Boe produced. The overall increase in general and administrative
expenses for the year ended December 31, 2013 was primarily due to additional payroll expenses associated with hiring
additional staff, merit increases and bonuses. Non-cash equity based compensation expense was $6.4 million and $6.3 million
for 2013 and 2012, respectively, and its cash based payroll tax costs of $0.2 million each year. The decrease in total general and
administrative expenses per Boe was attributable to increased production in 2013.
Interest Expense. Our interest expense for the year ended December 31, 2013 was approximately $3.3 million, compared
to approximately $1.8 million for the year ended December 31, 2012. The increase was due to higher borrowings outstanding
from our credit facility during 2013.
Year Ended December 31, 2012 Compared with Year Ended December 31, 2011.
Net income was approximately $29.9 million for the year ended December 31, 2012 compared to approximately $19.0
million for the year ended December 31, 2011, an increase of approximately $10.9 million. This increase was primarily
attributable to an increase in oil sales and the favorable net effect of our derivatives, partially offset by higher general and
administrative expenses (including equity-based compensation expense), higher depreciation, and lease operating expenses, as
a result of our continued growth.
Sales Revenues. Revenues from oil and natural gas sales for the year ended December 31, 2012 were approximately $61.6
million as compared to approximately $38.0 million for the year ended December 31, 2011. The increase in revenues was
primarily due to an increase in daily oil production which includes incremental volumes from acquisitions in 2012 and the last
six months of 2011.
On average, our production volumes for the year ended December 31, 2012 were approximately 698 MBoe, or
approximately 1,907 Boe per day. In comparison, our total production volumes for the year ended December 31, 2011 were
51
approximately 434 MBoe, or approximately 1,191 Boe per day on average. The increase in production volumes was primarily
due to ongoing waterflood response to injection as well as from wells drilled as part of the drilling program in our Southern
Oklahoma core area. Furthermore, the increase in production for the year ended December 31, 2012 reflects the impact from
various acquisitions of oil properties and additional working interest during 2012. Our average sales price per barrel of oil,
excluding commodity derivative contracts, for the year ended December 31, 2012 was $89.80, compared with $90.45 for the
year ended December 31, 2011.
Effects of Commodity Derivative Contracts. We utilize NYMEX contracts to hedge against changes in commodity prices.
Due to the period change in the mark-to-market value of these contracts, we recorded a net gain from our commodity hedging
program for the year ended December 31, 2012 of approximately $5.7 million, which was composed of a gain of approximately
$3.7 million on net cash settlements of derivative contracts and a non-cash gain on unsettled derivative contracts of
approximately $2.0 million. For the year ended December 31, 2011, we recorded a net gain from our commodity hedging
program of approximately $1.3 million, which was composed of a non-cash gain on unsettled derivative contracts of $3.4
million and a loss of approximately $2.1 million on net cash settlements of derivative contracts.
Lease Operating Expenses. Our lease operating expenses were approximately $10.9 million for the year ended
December 31, 2012, or $15.68 per Boe, compared to approximately $8.5 million for the year ended December 31, 2011, or
approximately $19.56 per Boe. The increase in total lease operating expenses for the year ended December 31, 2012 was
primarily attributable to the additional number of producing wells due to our drilling program and the additional oil properties
and working interest acquired during 2012. The decrease in lease operating expenses per Boe was due to the increased
production for the year ended December 31, 2012. Ad valorem taxes are also reflected in lease operating expenses. Ad valorem
taxes are levied on our properties in Colorado and are calculated as a percentage of our oil and natural gas revenues, excluding
the effects of our commodity derivative contracts, and a percentage of production equipment value.
Production Taxes. Our production taxes were approximately $2.0 million for the year ended December 31, 2012, or
approximately $2.82 per Boe for an effective tax rate of approximately 3.2%, compared to approximately $1.9 million for the
year ended December 31, 2011, or approximately $4.31 per Boe for an effective tax rate of approximately 4.9%. Production
taxes are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative
contracts. The State of Oklahoma, where most of our properties are located, currently imposes a production tax of 7.2% for oil
and natural gas properties and an excise tax of 0.095%. The decrease in price per Boe is due to some of our Southern Oklahoma
properties receiving a reduced production tax rate from Oklahoma’s Enhanced Recovery Project Gross Production Tax
Exemption.
Impairment Expense. Our impairment expense was approximately $1.3 million for the year ended December 31, 2012.
We review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or
circumstances indicate that the carrying value of those assets may not be recoverable. If the carrying amount exceeds the
property’s estimated fair value, we adjust the carrying amount of the property to fair value through a charge to impairment
expense. We recorded a $1.1 million and $0.2 million non-cash impairment charge within our miscellaneous core area gas wells
and our Southern Oklahoma core area, respectively. There was no impairment charge for the year ended December 31, 2011.
Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses on producing
properties for the year ended December 31, 2012 were approximately $10.3 million, or approximately $14.79 per Boe
produced, compared to approximately $6.8 million, or approximately $15.66 per Boe produced, for the year ended
December 31, 2011. The increase in depreciation, depletion and amortization expenses was primarily due to the increase in
total asset value of the oil and gas properties from our drilling program, the acquisitions of properties in our Hugoton Basin,
Southern and Northeastern Oklahoma core areas, and the purchase of additional working interest in our Southern Oklahoma
properties. The decrease per Boe produced was primarily due to the increase in total proved and proved developed reserves in
2012.
General and Administrative Expenses. Our general and administrative expenses were approximately $11.0 million for the
year ended December 31, 2012, or approximately $15.76 per Boe produced compared to approximately $3.8 million for the
year ended December 31, 2011 or approximately $8.68 per Boe produced. The increase in general and administrative expenses
for the year ended December 31, 2012 is primarily due to higher compensation costs of $6.5 million related to our equity-based
compensation expense, higher professional fees necessary to comply with public reporting requirements, and incremental costs
related to the hiring of additional staff. Compensation costs include non-cash equity-based compensation of $6.3 million and its
cash based payroll tax costs of $0.2 million.
Interest Expense. Our interest expense for the year ended December 31, 2012 was approximately $1.8 million, compared
to approximately $0.6 million for the year ended December 31, 2011. The increase was primarily due to increased borrowings
from our credit facility in 2012.
52
Liquidity and Capital Resources
Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness
obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in
the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including
weather, commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and
maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.
We believe a strong balance sheet is a necessary pre-requisite for creating sustainable growth in unitholder value. Our
liquidity position as of December 31, 2013 consisted of approximately $1.4 million of available cash, and $38.0 million of
available borrowings under our credit facility. Our primary use of capital has been for the acquisition and development of oil
and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor our liquidity and
the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit
facility.
As of December 31, 2013, our $250 million credit facility had a remaining borrowing capacity of $38.0 million ($150.0
million borrowing base less $112.0 million of outstanding borrowings). The borrowing base is re-determined on or about
April 30 and October 31 of each year. On November 5, 2013 the borrowing base of our credit facility was increased from
$130.0 million to $150.0 million. See Note 8 to the Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information about our credit facility.
Cash Flow
Cash flow provided by (used in) each type of activity was as follows:
Operating activities
Investing activities
Financing activities
$
Year Ended December 31,
$
2013
56,634
(50,423)
(5,830)
$
2012
47,717
(72,539)
25,647
2011
24,113
(42,045)
17,938
Operating Activities. Net cash provided by operating activities was approximately $56.6 million, $47.7 million and $24.1
million for the years ended December 31, 2013 and 2012 and 2011, respectively. The increase in December 31, 2013 from
December 31, 2012 was primarily due to higher revenues generated by higher production volumes and higher oil prices,
partially offset by a decrease in cash settlement derivatives and higher lease operating expenses and production taxes. The
increase in December 31, 2012 from December 31, 2011 was primarily due to higher revenues generated by higher production
volumes and higher cash settlements from derivatives, partially offset by higher general and administrative expenses.
Cash provided by operating activities is impacted by the prices we receive for oil and natural gas sales and production
volumes. Our production volumes in the future will in large part be dependent upon the results of past waterflood development
activities, increased production through our drilling programs, acquisitions, and results of future capital expenditures. Our
ability to fund planned capital expenditures and to make acquisitions, depends upon our future operating performance, oil and
natural gas prices, industry conditions, prices and other factors, some of which are beyond our control.
Investing Activities. Net cash used in investing activities was approximately $50.4 million, $72.5 million, and $42.0
million for the years ended December 31, 2013, 2012, and 2011, respectively. Cash used in investing activities during 2013
included $28.0 million for the purchase of additional working interest in the Cushing properties and certain Southern Oklahoma
properties. We also spent $22.4 million on capital expenditures, primarily for drilling, development and completion activities.
Cash used in investing activities during 2012 included $48.6 million for the purchase of certain oil properties in Northeastern
Oklahoma and additional working interest in our existing units in Southern Oklahoma. We also spent $24.0 million on capital
expenditures, primarily for drilling activities. Cash used in investing activities during 2011 included the acquisition of
properties as part of our initial public offering, and cash spent in development activities in Southern Oklahoma, including the
in-field drilling in these units.
Financing Activities. Our cash flows from financing activities consisted primarily of proceeds from and payments on our
credit facility, and distributions to unitholders. Net cash (used in) provided by financing activities was approximately ($5.8
million), $25.6 million, and $17.9 million for the year ended December 31, 2013, 2012 and 2011, respectively. During the year
ending December 31, 2013 cash used in financing activities included distributions to unitholders of approximately $39.8
53
million and net proceeds from our credit facility of approximately $34.0 million which were used to finance the acquisition of
additional working interest in our Northeastern Oklahoma and Southern Oklahoma core areas, and to develop capital projects.
During the year ended December 31, 2012, we received net proceeds from our credit facility of approximately $33.0 million in
addition to proceeds of $20.4 million from the sale of our common units which were used to finance the purchase of certain oil
properties located in our Northeastern Oklahoma core area and certain working interests in our existing units in the Southern
Oklahoma core area, develop capital projects and to pay down our line of credit. Conversely, we made distributions to
unitholders of approximately $27.7 million. During the year ended December 31, 2011, we received proceeds of $87.4 million
from our initial public offering net of offering costs, and net proceeds from our financing arrangements of $39.2 million which
were used to fund our drilling activity in Southern Oklahoma and the distribution of $110.9 million to redeem the limited
liability company membership units held by certain employees, directors, and non-affiliates in consideration for the merger of
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC into our subsidiary at the closing of our Initial Public Offering.
Capital Requirements
Our business requires continual investment to upgrade or enhance existing operations in order to increase and maintain
our production and the size our asset base. The primary purpose of growth capital is to acquire, develop and produce assets that
allow us to increase our production levels and asset base. We are actively engaged in the acquisition of oil and natural gas
properties. To date, we have funded acquisition transactions through a combination of cash and available borrowing capacity
under our current credit facility. We expect to finance any significant acquisition of oil and natural gas properties in 2014
through the issuance of equity, debt financing or borrowings under our revolving credit facility.
In 2013, our capital spending program for the development, growth and maintenance of our oil and natural gas properties,
including projects for our properties acquired in 2013, was approximately $22.3 million. We currently expect 2014 spending to
be approximately $30.0 million. We will consider adjustments to this capital program based on our assessment of additional
development opportunities that are identified during the year and the cash available to invest in our development projects.
Acquisitions. During May 2013, we acquired additional working interests in our Cushing properties located in the
Northeastern Oklahoma core area and in certain Southern Oklahoma units. We paid approximately $27.4 million in aggregate
consideration for the interests and the transaction was financed using proceeds from our revolving credit facility.
During 2012, our expenditures for acquisition of oil and natural gas properties totaled approximately $49.0 million and
included the acquisition of properties located in the Northeastern Oklahoma core area and additional working interests in our
existing units in the Southern Oklahoma and Hugoton Basin core areas. These transactions were financed using proceeds from
our revolving credit facility.
Credit Facility
We have a $250.0 million senior secure revolving credit facility that expires in November 2018. Borrowings under the
facility are secured by liens on not less than 80% of our assets and the assets of our subsidiaries. We may use borrowings under
the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership
purposes and for funding distributions to our unitholders. At December 31, 2013, we had approximately $112.0 million of
borrowings outstanding under the revolving credit facility. The facility requires us and our subsidiaries to maintain a leverage
ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX (as defined in the facility) of not more than 4.0 to 1.0,
and a current ratio of not less than 1.0 to 1.0. As of December 31, 2013, we were in compliance with all of the facility’s
financial covenants.
During 2013, our borrowing base under the revolving credit facility was increased from $130.0 million to $150.0 million
and Scotiabank was added to the lender group. Effective with this increase, the maturity terms of our credit facility were
extended to November 2018. No other material terms of the original credit agreement were amended. Borrowings under the
facility may not exceed our current borrowing base of $150.0 million. The borrowing base is determined by the lenders based
on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other matters that
may vary.
Borrowings under the revolving credit facility bear interest at a floating rate based on, at our election: (i) the greater of the
prime rate of the Royal Bank of Canada, the federal funds effective rate plus 0.50%, and the one month adjusted London
Interbank Offered Rate ("LIBOR") plus 1.0%, all of which are subject to a margin that varies from 0.75% to 1.75% per annum
according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base
then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the
borrowing base usage. For the year ended December 31, 2013, the average effective rate was approximately 2.7%. The unused
portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the
54
borrowing base usage. For additional information about our long-term debt, such as interest rates and covenants, please see
“Item 8. Financial Statements and Supplementary Data" contained herein.
Derivative Contracts
At December 31, 2013, our open commodity derivative contracts were in a net liability position with a fair value of $1.4
million. All of our commodity derivative contracts are with major financial institutions that are also members of our banking
group. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative
instruments under lower commodity prices and we could incur a loss. As of December 31, 2013, all of our counterparties have
performed pursuant to their commodity derivative contracts.
All of our derivative contracts for 2014 and 2015 are either swaps with fixed settlements or collars (calls and puts). These
instruments limit our exposure to declines in prices, but also limit the benefits if prices increase. We do not designate
commodity derivative contracts as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the
change in the fair value of unsettled derivative contracts is recorded in current period earnings as a non-cash gain or loss. When
prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses
due to changes in the fair value of our commodity derivative contracts. Net settlement gains or losses on derivative contracts
only arise from net payments made or received on monthly settlements or if a commodity derivative contract is terminated prior
to its expiration.
See Note 5 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data"
for additional information regarding our derivative contracts.
Our risk management program is intended to reduce our exposure to commodity prices and interest rates and to assist
with stabilizing cash flows. Accordingly, we utilize derivative financial instruments to manage our exposure to commodity
price fluctuations and fluctuations in location differences between published index prices and the NYMEX futures prices. Our
policies do not permit the use of derivatives for speculative purposes. As of December 31, 2013, we have commodity
derivative contracts covering approximately 79% and 10% of our calendar years 2014 and 2015 average daily oil production
(as estimated from the projection of our oil production in our audited proved reserves as of December 31, 2013).
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2013. The contractual obligations we will
actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.
Long-term debt (1)
Interest on long-term debt (2)
Obligations Due in Period (in thousands)
2014
2015
2016
2017
2018
Total
$
$
— $
— $
— $
— $ 112,000
$ 112,000
3,024
3,024
3,024
3,024
2,560
14,656
3,024
$
3,024
$
3,024
$
3,024
$ 114,560
$ 126,656
For purposes of this table, we have assumed that the borrowings under our revolving credit facility as of
December 31, 2013 will not be repaid until the maturity date on November 5, 2018.
Interest obligation for borrowings under our revolving credit facility assumes borrowings outstanding at
December 31, 2013 will remain outstanding until the maturity date of the facility. The interest obligation is based
on a 2.7% borrowing rate at December 31, 2013.
Our ARO is not included in the table above given the uncertainty regarding the actual timing of such expenditures. The
total amount of our ARO at December 31, 2013 is $3.9 million.
Off–Balance Sheet Arrangements
As of December 31, 2013, we had no off–balance sheet arrangements.
Recently Issued Accounting Pronouncements
No new accounting pronouncements issued or effective during the year ended December 31, 2013 have had or are
expected to have a material impact on our consolidated financial statements.
55
Total
(1)
(2)
ITEM 7A. Quantitative and Qualitative Disclosure about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and credit risk. The primary
objective of the following information is to provide quantitative and qualitative information about our potential exposure to
market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and
interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of
reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative
trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil production. Realized pricing is primarily
driven by the spot market prices applicable to the prevailing price for oil. Pricing for oil has been volatile and unpredictable for
several years, and this volatility is expected to continue in the future. The prices we receive for our oil production depend on
many factors outside of our control, such as the strength of the global economy and changes in supply and demand.
To reduce the impact of fluctuations in oil prices on our revenues, or to protect the economics of property acquisitions, we
have entered into, and may enter into, additional commodity derivative contracts for a portion of our oil production. The
agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected
future oil production over a fixed period of time. These hedging activities are intended to manage our exposure to oil price
fluctuations. We do not enter into derivative contracts for speculative trading purposes.
Our oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not
require our counterparties to our derivative contracts to post collateral, it is our policy to enter into derivative contracts only
with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive
market makers. We evaluate the credit standing of such counterparties by reviewing their credit ratings. The counterparties to
our derivative contracts currently in place are lenders under our credit facility and have investment grade ratings. We expect to
enter into future derivative contracts with these or other lenders under our credit facility whom we expect will also carry
investment grade ratings.
Our commodity price risk management activities could have the effect of reducing net income and the value of our
securities. The fair value of our oil commodity contracts and swaps at December 31, 2013 was a net liability of approximately
$1.4 million. A 10% change in oil prices, with all other factors held constant, would result in a change in the fair value
(generally correlated to our estimated future net cash flows from such instruments) of our oil commodity contracts and swaps
of approximately $7.4 million. See Note 5 to the Consolidated Financial Statements included in “Item 8. Financial Statements
and Supplementary Data” for additional information.
Interest Rate Risk
Our exposure to changes in interest rates relates primarily to debt obligations. At December 31, 2013, we had debt
outstanding of $112.0 million, with an effective interest rate of 2.7%. Assuming no change in the amount outstanding, the
impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $0.3 million on an
annual basis. Our revolving credit facility allows borrowings up to $150.0 million at an interest rate ranging from LIBOR plus
1.75% to LIBOR plus 2.75% or the prime rate plus 0.75% to the prime rate plus 1.75% depending on the amount borrowed.
The prime rate will be the United States prime rate as announced from time-to-time by the Royal Bank of Canada. See Note 8
to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional
information.
Counterparty and Customer Credit Risk
We are subject to credit risk due to the concentration of our revenues attributable to a small number of customers for our
current 2013 production. The inability or failure of any of our customers to meet its obligations to us or its insolvency or
liquidation may adversely affect our financial results. However, Enterprise, Coffeyville, Valero, and National have positive
payment histories. As of December 31, 2013, Enterprise and Valero each have investment grade credit ratings.
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Mid-Con Energy Partners, LP
We 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, 2013 and 2012, and the related consolidated statements of
operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. These
financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. We were not engaged to perform an audit of the Partnership's internal control over
financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of
the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of Mid-Con Energy Partners, LP and subsidiaries as of December 31, 2013 and 2012, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with
accounting principles generally accepted in the United States of America.
GRANT THORNTON LLP
Tulsa, Oklahoma
March 5, 2014
57
Mid-Con Energy Partners, LP and subsidiaries
Consolidated Balance Sheets
(in thousands, except number of units)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable:
Oil and natural gas sales
Other
Derivative financial instruments
Prepaids and other
Total current assets
PROPERTY AND EQUIPMENT, at cost:
Oil and natural gas properties, successful efforts method:
Proved properties
Accumulated depletion, depreciation and amortization
Total property and equipment, net
DERIVATIVE FINANCIAL INSTRUMENTS
OTHER ASSETS
Total assets
CURRENT LIABILITIES:
Accounts payable
Trade
Related parties
LIABILITIES AND EQUITY
Derivative financial instruments
Accrued liabilities
Total current liabilities
OTHER LONG-TERM LIABILITIES
LONG-TERM DEBT
ASSET RETIREMENT OBLIGATIONS
COMMITMENTS AND CONTINGENCIES
EQUITY, per accompanying statements:
Partnership equity
General partner interest
Limited partners-19,319,362 and 18,990,849 units issued and outstanding as of
December 31, 2013 and 2012, respectively
Total equity
Total liabilities and equity
See accompanying notes to consolidated financial statements
58
December 31,
2013
2012
$
1,434
$
1,053
6,778
104
153
191
8,660
216,680
(36,148)
180,532
48
843
6,413
603
3,679
25
11,773
167,036
(21,727)
145,309
858
650
$
190,083
$
158,590
$
2,184
$
2,982
1,627
432
7,225
128
112,000
3,942
1,716
65,072
66,788
2,168
3,036
—
315
5,519
—
78,000
2,890
1,814
70,367
72,181
$
190,083
$
158,590
Mid-Con Energy Partners, LP and subsidiaries
Consolidated Statements of Operations
(in thousands, except per unit data)
Revenues:
Oil sales
Natural gas sales
Net settlements on derivatives
Gain (loss) on unsettled derivatives, net
Total revenues
Operating costs and expenses:
Lease operating expenses
Oil and natural gas production taxes
Impairment of proved oil and natural gas properties
Dry holes and abandonments of unproved properties
Depreciation, depletion and amortization
Accretion of discount on asset retirement obligations
General and administrative
Total operating costs and expenses
Income from operations
Other income (expense):
Interest income and other
Interest expense
Gain on sale of assets
Other revenue and expenses, net
Total other income (expense)
Net income
Computation of net income per limited partner unit:
General partners’ interest in net income
Limited partners’ interest in net income
Net income per limited partner unit:
Basic
Diluted
Weighted average limited partner units outstanding:
Common limited partner units (basic)
Common limited partner units (diluted)
Year Ended December 31,
2013
2012
2011
$
85,080
$
60,887
$
656
288
(5,963)
80,061
16,366
3,817
1,578
—
14,421
173
12,244
48,599
31,462
9
(3,282)
—
—
(3,273)
28,189
518
27,671
1.44
1.44
19,234
19,249
$
$
$
$
$
674
3,710
2,004
67,275
10,948
1,965
1,296
—
10,324
126
11,000
35,659
31,616
10
(1,764)
—
—
(1,754)
29,862
584
29,278
1.62
1.62
18,049
18,049
$
$
$
$
$
$
$
$
$
$
36,813
1,218
(2,157)
3,437
39,311
8,491
1,869
—
813
7,160
78
3,767
22,178
17,133
216
(578)
1,621
576
1,835
18,968
379
18,589
1.05
1.05
17,640
17,640
See accompanying notes to consolidated financial statements
59
Mid-Con Energy Partners, LP and subsidiaries
Consolidated Statements of Cash Flows
(in thousands)
Cash Flows from Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Year Ended December 31,
2013
2012
2011
$
28,189
$
29,862
$
18,968
Depreciation, depletion and amortization
Debt placement fee amortization
Accretion of discount on asset retirement obligations
Impairment of proved oil and natural gas properties
Dry holes and abandonments of unproved properties
Loss (gain) on unsettled derivative instruments, net
Equity-based compensation
Gain on sale of assets
Changes in operating assets and liabilities:
Accounts receivable
Other receivables
Prepaid and other
Accounts payable and accrued liabilities
Revenues payable
Advance billings and other
14,421
168
173
1,578
—
5,963
6,376
—
(365)
499
(526)
158
—
—
10,324
131
126
1,296
—
(2,004)
6,323
—
(1,395)
(603)
2,159
1,498
—
—
Net cash provided by operating activities
56,634
47,717
Cash Flows from Investing Activities:
Additions to oil and natural gas properties
Acquisitions of oil and natural gas properties
Additions to other property and equipment
Proceeds from sale of other property and equipment
Proceeds from sale of investment in subsidiary, net of cash sold
Proceeds from sale of property and equipment to subsidiary, net of cash sold
(22,366)
(28,057)
(23,960)
(48,579)
—
—
—
—
—
—
—
—
7,160
—
78
—
813
(3,437)
1,671
(1,621)
(4,454)
—
415
4,608
32
(120)
24,113
(32,654)
(16,026)
(679)
1,219
2,095
4,000
Net cash used in investing activities
(50,423)
(72,539)
(42,045)
Cash Flows from Financing Activities:
Proceeds from line of credit
Payments on line of credit
Distributions paid
Borrowings on note payable
Payments on note payable
Proceeds from initial public offering, net of discount
Repurchase of common units
Issuance of common units
Net cash (used in) provided by financing activities
Net increase in cash and cash equivalents
Beginning cash and cash equivalents
Ending cash and cash equivalents
Supplemental Cash Flow Information:
Cash paid for interest
Non-Cash Investing and Financing Activities:
Accrued capital expenditures - oil and natural gas properties
Deferred gain on sale of property and equipment to subsidiary
105,000
(71,000)
(39,830)
—
—
—
—
—
(5,830)
381
1,053
1,434
2,803
926
$
$
$
80,800
(47,800)
(27,705)
—
—
—
—
20,352
25,647
825
228
1,053
1,561
1,005
$
$
$
— $
— $
68,564
(29,385)
(110,937)
412
(84)
87,397
(1)
1,972
17,938
6
222
228
535
3,331
1,208
$
$
$
$
See accompanying notes to consolidated financial statements
60
Balance, December 31, 2010
Contributions
Repurchase of common units
Equity-based compensation
Net income
Balance, November 30, 2011
Mid-Con Energy Partners, LP and subsidiaries
Consolidated Statements of Changes in Equity
(In thousands)
Contributed
Capital
$
52,923
$
1,350
(4)
1,671
—
$
55,940
$
Notes
Receivable
from Officers,
Director and
Employees
Accumulated
Earnings/
(Deficit)
Total
Owners’
Equity
(1,833) $
(106)
3
—
—
(1,936) $
(8,018) $
—
—
—
17,927
9,909
$
43,072
1,244
(1)
1,671
17,927
63,913
General
Partner
Limited Partner
Units
Amount
Total
Equity
1,278
12,240
$
62,635
$
5,400
87,395
63,913
87,395
Combination transaction with Mid-Con Energy I, LLC
and Mid-Con Energy II, LLC
Issuance of common units in initial public offering
Distribution to unitholders of Mid-Con Energy I, LLC and
Mid-Con Energy II, LLC
Net income
Balance, December 31, 2011
Equity-based compensation
Issuance of common units
Distributions
Net income
Balance, December 31, 2012
Equity-based compensation
Distributions
Net income
Balance, December 31, 2013
$
$
$
$
—
—
21
1,299
119
378
(537)
555
1,814
115
(731)
518
1,716
—
—
(109,000)
1,020
(109,000)
1,041
17,640
$
42,050
$
351
1,000
—
—
6,204
19,974
(27,168)
29,307
18,991
$
70,367
$
328
—
—
6,133
(39,099)
27,671
19,319
$
65,072
$
43,349
6,323
20,352
(27,705)
29,862
72,181
6,248
(39,830)
28,189
66,788
See accompanying notes to consolidated financial statements
61
Mid-Con Energy Partners, LP and subsidiaries
Notes to Consolidated Financial Statements
Note 1. Organization and Nature of Operations
Mid-Con Energy Partners, LP (“we,” “our,” “us,” the “Partnership,” the "Company") is a publicly held Delaware limited
partnership formed in December 2011, that engages in the acquisition, development and production of oil and natural gas
properties in North America, with a focus on the Mid-Continent region of the United States. Our common units are traded on
the NASDAQ Global Select Market under the symbol “MCEP”. Our general partner is Mid-Con Energy GP, LLC, a Delaware
limited liability company.
Note 2. Summary of Significant Accounting Policies
Basis of presentation and principles of consolidation
The accompanying financial statements and related notes present our consolidated financial position as of December 31,
2013 and 2012. These financial statements also include the results of our operations, cash flows and changes in equity for the
years ended December 31, 2013, 2012 and 2011.
The accompanying consolidated financial statements have been prepared in accordance with accounting principles
generally accepted in the United States of America (“GAAP”). All intercompany transactions and account balances have been
eliminated. Additionally, our financial statements for previous periods include certain reclassifications that were made to
conform to the current period presentation. Such reclassifications have no impact on previously reported total assets, total
liabilities, net income or equity.
We aggregate all of our oil and natural gas properties into one business segment engaged in the exploration, development
and production of oil and natural gas.
Use of estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results
could differ from those estimates. Significant items subject to those estimates and assumptions include: depletion of oil and gas
properties which is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development
expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous
uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant
estimates include, but are not limited to, asset retirement obligations, fair value of business combinations, fair value of
derivative financial instruments, purchase price allocation of business acquisitions and fair value of equity-based compensation.
Cash and cash equivalents
We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of
three months or less to be cash equivalents. We have not experienced any losses in such accounts.
Accounts receivable
Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the
financial strength of our customers and bad debts are recorded based on an account–by–account review after all means of
collection have been exhausted, and the potential recovery is considered remote. As of December 31, 2013 and 2012, we did
not have any reserves for doubtful accounts, and we did not incur any expenses related to bad debts in any period presented.
Revenue recognition
We follow the sales method of accounting for crude oil and natural gas revenues. Under this method, revenues are
recognized based on our share of actual proceeds from oil and gas sold to purchasers. Natural gas revenues would not have
been significantly altered for the period presented had the entitlements method of recognizing natural gas revenues been
utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability is recorded. We had no significant
natural gas imbalances at December 31, 2013 or 2012.
62
Oil and natural gas properties
We utilize the successful efforts method of accounting for our oil and natural gas properties. Under this method all costs
associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs
are expensed. Capitalized costs relating to proved properties are depleted using the units-of-production method based on proved
reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method
using proved developed reserves on a field basis.
Capitalized costs of individual properties abandoned or retired are charged to accumulated depletion, depreciation and
amortization. Proceeds from sales of individual properties are credited to property costs. No gain or loss is recognized until the
entire amortization base (field) is sold or abandoned.
Costs of significant nonproducing properties and wells in the process of being drilled are excluded from depletion until
such time as the proved reserves are established or impairment is determined. Costs of significant development projects are
excluded from depreciation until the related project is completed. We capitalize interest, if debt is outstanding, on expenditures
for significant development projects until such projects are ready for their intended use. We had no capitalized interest during
any of the periods presented.
Impairment of Long-Lived Assets
We review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under
the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets
may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined
as the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and
possible oil and gas reserves over the economic life of the reserves based on our expectations of future oil and gas prices and
costs. We review our oil and gas properties by amortization base (field) or by individual well for those wells not constituting
part of an amortization base.
For the year ended December 31, 2013 and 2012, we recorded non-cash impairment charges of approximately $1.6
million and $1.3 million, respectively, related to our producing properties within our miscellaneous core areas. For the year
ended December 31, 2011 no impairment charge was recorded. These non-cash charges are included in "impairment of proved
oil and natural gas properties” line item in the accompanying consolidated statements of operations. The fair value of the
properties was measured by utilizing the estimated cash flow reported in the audited reserve report. This report was adjusted for
future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 3 inputs
in the fair value hierarchy described in Note 6. The fair values of proved properties are measured using valuation techniques
consistent with the income approach, converting future cash flow to a single discounted amount. Significant inputs used to
determine the fair values of proved properties include estimates of reserves, future operating and development costs, future
commodity prices and market-based weighted average cost of capital rate. The underlying commodity prices embedded in our
estimated cash flow are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve
pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact
realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities,
anticipated drilling and operating costs, anticipated production taxes and future expected oil and natural gas prices. Cash flow
estimates for the impairment testing excluded derivative instruments used to mitigate the price risk related to lower future oil
and natural gas prices. The impairments were caused by the decrease in reserves of our oil and natural gas properties in 2013
and 2012. These impairments have no impact on our cash flow, liquidity position, or debt covenants.
We did not have any abandonment expenses for the years ended December 31, 2013 and 2012, and we recognized
approximately $0.8 million as abandonment expense for the year ended December 31, 2011, related to our unproved oil and gas
properties.
Other property and equipment
Other property and equipment is stated at historical cost and is comprised of software, vehicles, office equipment, and
field service equipment. Costs incurred for normal repairs and maintenance are charged to expense as incurred, unless they
extend the useful life of the asset. Depreciation is calculated using the straight-line method based on estimated useful lives of
the assets ranging from 3 to 15 years and is included in the accumulated depreciation, depletion and amortization totals. All of
the other property and equipment was sold to one of our Affiliates at June 30, 2011. Consequently, there was no depreciation
expense related to other property and equipment for the years ended December 31, 2013 and 2012. For the year ended
December 31, 2011, depreciation expense related to other property and equipment totaled approximately $0.3 million.
63
Asset retirement obligations
We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end
of oil and natural gas production operations. These asset retirement obligations (“ARO”) are primarily associated with plugging
and abandoning wells. Determining the future restoration and removal requires management to make estimates and judgments
because most of the removal obligations are many years in the future and contracts and regulations often have vague
descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory,
political, environmental, safety and public relations considerations. We are required to record the fair value of a liability for an
ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset.
We typically incur this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its
future value and the capitalized 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 costs differ from the recorded liability.
Inherent to the present value calculation are numerous estimates, assumptions 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. 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. Increases in the discounted retirement obligation liability and related oil and natural gas assets resulting
from the passage of time will be reflected as additional accretion and depreciation expense in the statements of operations.
Derivatives and hedging
Our risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash
flows. Accordingly, we utilize derivative financial instruments to manage our exposure to commodity price fluctuations in
location differences between published index prices and the NYMEX futures prices. These transactions are primarily in the
form of either swaps with fixed settlements or collars (calls and puts). Our policies do not permit the use of derivatives for
speculative or trading purposes.
We do not designate commodity derivative contracts as hedges for accounting purposes; therefore, the mark-to-market
adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings as a
non-cash gain or loss. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of
non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Net settlement gains or
losses on derivative contracts only arise from net payments made or received on monthly settlements or if a commodity
derivative contract is terminated prior to its expiration. Pursuant to the accounting standard that permits netting of assets and
liabilities where the right of offset exists, we present the fair value of derivative financial instruments on a net basis by
counterparty.
Other revenue and expense, net
Prior to June 30, 2011, we received fees for the operation of jointly-owned oil and gas properties and recorded such
reimbursements as reductions of other revenue and expense, net. Such fees totaled approximately $2.1 million for the year
ended December 31, 2011. These fees are now received by our affiliate, Mid-Con Energy Operating.
Equity-based compensation
The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value
of compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria
vest when it is probable that the performance criteria will be met. Compensation expense for these awards is recorded upon
vesting, based on their grant-date fair value. Generally, no compensation expense is recognized for equity instruments that do
not vest. We recorded equity-based compensation expense of $6.6 million, $6.5 million and $1.7 million for the years ended
December 31, 2013, 2012 and 2011, respectively, which includes non-cash equity based compensation and cash-based
compensation costs for employer taxes reimbursed to Mid-Con Energy Operating. The non-cash equity based compensation
portion totaled $6.4 million, $6.3 million and $1.7 million for 2013, 2012 and 2011, respectively. In 2013 and 2012, the cash-
based costs for employer taxes totaled approximately $0.2 million per year. There were no employer tax costs associated with
the 2011 equity-based compensation recognized as this transaction was part of the contribution, conveyance and merger
agreement signed on December 20, 2011. See Note 10 to the Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information.
64
Debt placement fee
Debt placement fees are stated at cost, net of amortization, which is computed using the straight-line method. At
December 31, 2013 and 2012, net debt issuance costs of approximately $0.4 million and $0.7 million, respectively, are included
in "other assets" on the consolidated balance sheets. When debt is retired before its scheduled maturity date, we write off any
remaining issuance costs associated with that debt.
Income taxes
We are a partnership that is not taxable for federal income tax purposes. As such, we do not directly pay federal income
tax. As appropriate, our taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or
losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax
purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
Net income per limited partner unit
Basic and diluted net income per limited partner unit is determined by dividing net income available to the limited
partners, after deducting the general partner’s interest in net income, by the weighted average number of outstanding limited
partner units during the period.
Business segment reporting
We operate in one reportable segment: the exploration, development and production of oil and natural gas properties. All
of our operations are located in the United States.
Note 3. Acquisitions
Acquisitions 2013
In May 2013, we acquired additional working interests in our Cushing properties located in the Northeastern Oklahoma
core area and in certain Southern Oklahoma units. The results of operations of these properties have been included in the
consolidated financial statements since the acquisition date. We paid approximately $27.4 million in aggregate consideration
for the interests and the transaction was accounted for under the acquisition method. The transaction was financed using
proceeds from our credit facility. The recognized fair values of the identifiable assets of the Cushing properties acquired and
liabilities assumed in connection with the acquisition are as follows (in thousands):
Fair Value of net assets:
Oil and natural gas properties
Total assets acquired
Fair Value of net liabilities assumed:
Asset retirement obligation
Net assets acquired
Acquisitions 2012
$
$
$
28,318
28,318
906
27,412
In June 2012, we acquired certain oil properties located in the Northeastern Oklahoma core area, and additional working
interests in our existing units in the Southern Oklahoma core area, in unrelated transactions. We paid approximately $16.4
million in aggregate consideration for these properties.
In October 2012, we acquired additional working interests in our War Party Unit I and War Party Unit II located in the
Hugoton Basin core area. We paid approximately $3.7 million for the interests.
In November 2012, we acquired a 100% working interest in the Clawson Ranch Waterflood Unit (“Clawson Ranch”) in
our Hugoton Basin core area from multiple parties. We paid approximately $28.9 million in consideration for the properties and
interests. The transactions were financed using proceeds from our credit facility. The purchase price for these properties
represented approximately 30% of the total value of Mid-Con Energy Partners, LP assets as of December 31, 2011. The
recognized fair values of the identifiable assets of the Clawson Ranch acquired and liabilities assumed in connection with the
acquisition are as follows (in thousands):
65
Fair Value of net assets:
Oil and natural gas properties
Total assets acquired
Fair Value of net liabilities assumed:
Asset retirement obligation
Net assets acquired
$
$
$
29,105
29,105
249
28,856
The following table reflects pro forma revenues, net income and net income per limited partner unit for the years ended as
if the Clawson Ranch acquisition had taken place on January 1, 2011. These unaudited pro forma amounts do not purport to be
indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the
future (in thousands):
Revenues
Net income
Net income per limited partner unit
Basic and diluted
Note 4. Equity Awards
2012
73,443
32,112
2011
47,677
22,408
$
1.74
$
1.24
We have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and
directors of our general partner and its affiliates, including Mid-Con Energy Operating, LLC. (“Mid-Con Energy Operating”),
who perform services for us. The Long-Term Incentive Program allows for the award of unit options, unit appreciation rights,
restricted units, phantom units, distribution equivalent rights granted with phantom units, and other types of awards and it is
administered by the members of our general partner (the "Founders") and approved by the Board of Directors of the general
partner. The Long-Term Incentive Program permits the grant of awards covering an aggregate of 1,764,000 units under the
Form S-8 we filed with the SEC on January 25, 2012. If an employee terminates employment prior to the restriction lapse date,
the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. The following table shows
the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2013:
Approved and authorized awards
Unrestricted units granted, included vested units
Restricted units granted, net of forfeitures and vesting
Phantom units issued, net of forfeitures
Awards available for future grant
Number of
Common Units
1,764,000
(558,773)
(120,589)
(43,000)
1,041,638
Equity Awards
We account for restricted units as equity awards since these awards will be settled by issuing common units. These
restricted units vest over a three-year period and we assume a 10% forfeiture rate. A summary of our restricted units awarded
for the years ended December 31, 2013 and 2012 is presented below:
66
Restricted awards:
Outstanding at December 31, 2011
Units granted
Units forfeited
Restricted units outstanding at December 31, 2012
Units granted
Units vested
Units forfeited
Outstanding at December 31, 2013
Liability Awards
Number of
Restricted Units
Average Grant Date
Fair Value per Unit
—
62,658
(7,509)
55,149
96,185
(18,399)
(12,346)
120,589
$21.26
$21.45
$23.86
$21.24
$22.13
We account for phantom units issued during 2013 as liability awards due to the Long-Term Incentive Program’s provision
allowing the Board of Directors, at its discretion, to settle the award in either cash or common units. The phantom units are an
incentive based equity award that will be issued to employees or members of the board of directors over a three-year vesting
period subject to attaining certain production target levels. The phantom units are not eligible to receive quarterly distributions
until they vest. The fair value of these phantom units is remeasured at the end of each reporting period based on the current
market price of our common units discounted for expected forfeitures and distribution payments during the vesting period in
addition to an adjustment related to management's expectation of the Partnership's ability to attain the stated production target
levels. These costs are reported as a component of general and administrative expense in our consolidated statement of
operations and are net of estimated forfeitures. These units are subject to forfeiture and we assume a 10% forfeiture rate. As of
December 31, 2013 we recorded approximately $0.1 million of compensation expense associated with the phantom units.
Activity related to these phantom units is as follows:
Nonvested phantom units as of December 31, 2012
Issued in July 2013
Forfeited
Nonvested phantom units as of December 31, 2013
Number of Units
—
50,000
(7,000)
43,000
The weighted average grant-date fair value of unrestricted unit grants and restricted units granted was $22.89 during the
year ended December 31, 2013. As of December 31, 2013 there was approximately $1.9 million of unrecognized
compensation costs related to nonvested units. The cost is expected to be recognized over a weighted average period of
approximately 2.12 years. Additionally, there was approximately $0.6 million of unrecognized compensation cost related to the
phantom units based on the closing price of our common units at December 31, 2013. The cost is expected to be recognized
over the next 2.5 years.
We recognized $6.6 million, $6.5 million and $1.7 million of equity-based compensation expense for the years ended
December 31, 2013, 2012 and 2011, respectively. These costs are reported as a component of general and administrative
expense in our consolidated statement of operations.
Note 5. Derivative Financial Instruments
Our risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash
flows. Accordingly, we utilize derivative financial instruments to manage our exposure to commodity price fluctuations and
fluctuations in location differences between published index prices and the NYMEX futures prices. Our policies do not permit
the use of derivatives for speculative purposes.
67
At December 31, 2013 and 2012 our open positions consisted of crude oil price collar (calls and puts) contracts and crude
oil price swap contracts. Under commodity swap agreements, we exchange a stream of payments over time according to
specified terms with another counterparty. In a typical commodity swap agreement, we agree to pay an adjustable or floating
price tied to an agreed upon index for the oil commodity and in return receive a fixed price based on notional quantities. A
collar is a combination of a put purchased by a party and a call option sold by the same party. In a typical collar transaction, if
the floating price based on a market index is below the floor price, we receive from the counterparty an amount equal to this
difference multiplied by the specified volume. If the floating price exceeds the floor price and is less than the ceiling price, no
payment is required by either party. If the floating price exceeds the ceiling price, we must pay the counterparty an amount
equal to the difference multiplied by the specific quantity.
We have elected not to designate commodity derivative contracts as hedges for accounting purposes; therefore, the mark-
to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period
earnings as a non-cash gain or loss. When prices for oil are volatile, a significant portion of the effect of our hedging activities
consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Net settlement
gains or losses on derivative contracts only arise from net payments made or received on monthly settlements or if a
commodity derivative contract is terminated prior to its expiration. Pursuant to the accounting standard that permits netting of
assets and liabilities where the right of offset exists, we present the fair value of derivative financial instruments on a net basis
by counterparty.
At December 31, 2013 we had the following oil derivative open positions:
Period Covered
Swaps - 2014
Swaps - 2015
Collars - 2015
Weighted
Average
Floor
Price
Weighted
Average
Ceiling
Price
Weighted
Average
Fixed
Price
$
$
93.56
90.05
$
85.00
$
95.13
Total
Bbls
Hedged/day
1,973
164
123
NYMEX
Index
WTI
At December 31, 2013, we recorded the estimated fair value of the derivative contracts as a net liability of $1.4 million.
At December 31, 2012 we had the following oil derivative open positions:
Period Covered
Swaps - 2013
Collars - 2013
Swaps - 2014
Weighted
Average
Fixed
Price
Weighted
Average
Floor
Price
Weighted
Average
Ceiling
Price
$
$
98.26
93.71
$
97.67
$
108.08
Total
Bbls
Hedged/day
1,545
296
1,644
NYMEX
Index
WTI
At December 31, 2012, we recorded the estimated fair value of the derivative contracts as a net asset of $4.5 million.
Our oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not
require our counterparties to our derivative contracts to post collateral, it is our policy to enter into derivative contracts only
with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive
market makers. We evaluate the credit standing of such counterparties by reviewing their credit rating. The counterparties to
our derivative contracts currently in place are lenders under our credit facility and have investment grade ratings.
The following tables summarizes the gross fair value by the appropriate balance sheet classification, even when the
derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at
December 31, 2013 and 2012 (in thousands):
68
2013
Assets
Derivative financial instrument - current asset
Derivative financial instrument - long-term asset
Total
Liabilities
Derivative financial instrument - current liability
Derivative financial instrument - long-term liability
Total
Net liability
2012
Assets
Derivative financial instrument - current asset
Derivative financial instrument - long-term asset
Total
Liabilities
Derivative financial instrument - current liability
Derivative financial instrument - long-term liability
Total
Net asset
Gross
Amounts
Recognized
Gross Amounts
Offset in the
Consolidated
Balance Sheet
Net Amounts
Presented in the
Consolidated
Balance Sheet
541
48
589
$
$
388
—
388
$
$
153
48
201
(2,015) $
—
(2,015) $
(388) $
—
(388) $
(1,627)
—
(1,627)
(1,426) $
— $
(1,426)
Gross
Amounts
Recognized
Gross Amounts
Offset in the
Consolidated
Balance Sheet
Net Amounts
Presented in the
Consolidated
Balance Sheet
3,843
1,486
5,329
$
$
(164) $
(628)
(792) $
— $
346
346
$
— $
(346)
(346) $
3,843
1,140
4,983
(164)
(282)
(446)
4,537
— $
4,537
$
$
$
$
$
$
$
$
$
$
The following table summarizes the gains and losses reported in earnings related to the commodity derivative financial
instruments within the consolidated statements of operations:
Net settlements on derivatives
Gain (loss) on unsettled derivatives, net
Total gain (loss) on derivatives, net
December 31,
2013
2012
2011
$
$
$
288
(5,963)
(5,675) $
3,710
2,004
5,714
$
$
(2,157)
3,437
1,280
69
Note 6. Fair Value Disclosures
The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts payable and derivative
financial instruments approximate their fair values. The carrying amount of long-term debt under our credit facility
approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market
rates available to us.
We account for our oil and natural gas commodity derivatives at fair value. The fair value of derivative financial
instruments is determined utilizing NYMEX closing prices for the contract period.
Fair value measurements
Fair 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 market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy that is
intended to increase consistency and comparability in fair value 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 to the 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 market that management has the ability to access.
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 observable either directly or indirectly for substantially the full term of the asset or liability.
Level 3—Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs
that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own
assumptions about the assumptions a market participant would use 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 value measurement is categorized is based on the lowest level input that is significant to the fair value
measurement in its entirety. Changes in the observability of valuation 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 years ended December 31, 2013, 2012 and
2011.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
We account for commodity derivatives at fair value on a recurring basis. We use certain pricing models to determine the
fair value of our derivative financial instruments. Inputs to the pricing models include publicly available prices from a
compilation of data gathered from third parties and brokers. We validate the data provided by third parties by understanding the
pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and
confirming that those securities trade in active markets. See Note 5 to the Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for a summary of our derivative financial instruments.
Assets and liabilities measured at fair value on a nonrecurring basis
We estimate the fair value of the AROs based on discounted cash flow projections using numerous estimates, assumptions
and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; and inflation rates. See Note 7 to the Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for a summary of changes in AROs.
We review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or
circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the
sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, we
recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the
asset and reduces the carrying amount of the asset. Estimating future cash flows involves the use of judgments, including
estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future
commodity prices, capital expenditures and production costs. For the year ended December 31, 2013, we recorded a non-cash
impairment charge of approximately $1.6 million within our miscellaneous core area. For the year ended December 31, 2012
70
we recorded a non-cash impairment charge of approximately $1.3 million , approximately $1.1 million of the impairment
charge related to our natural gas producing properties. For the year ended December 31, 2011 no impairment charge was
recorded. All of the impairment charges are due to a decline in estimated proved and probable reserve values.
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 of December 31, 2013 and 2012:
December 31, 2013
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Derivative financial instruments- asset
Derivative financial instruments- liability
Net financial assets
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Asset retirement obligations
Impairment of proved oil and gas properties
December 31, 2012
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Derivative financial instruments- asset
Derivative financial instruments- liability
Net financial assets
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Asset retirement obligations
Impairment of proved oil and gas properties
$
$
$
$
$
$
$
$
Level 1
Level 2
Level 3
(in thousands)
— $
— $
— $
— $
— $
— $
—
— $
— $
— $
201
$
1,627
(1,426) $
—
—
—
— $
— $
879
1,578
4,983
446
4,537
$
$
—
—
—
— $
— $
845
1,296
Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates
involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs
for the years ended December 31, 2013 and 2012.
Note 7. Asset Retirement Obligations
Our AROs represent the estimated present value of the amount we will incur to plug, abandon and remediate our
producing properties at the end of their production lives, in accordance with applicable state laws. We determine our ARO by
calculating the present value of estimated cash flow related to the liability. Each year we review and to the extent necessary,
revise our ARO estimates.
AROs are recorded as a liability at their estimated present value at the various assets’ inception, with the offsetting charge
to oil and gas properties. Periodic accretion of the discounted estimated liability is recorded in our consolidated statement of
operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the
assets based on proved developed reserves.
Changes in our ARO obligations for the periods indicated are presented in the following table:
71
Years Ended December 31,
2013
2012
2011
Asset retirement obligation - beginning of period
Liabilities incurred for new wells and interest
Disposition of wells
Revision of estimates
Accretion expense
(in thousands)
$
2,890
$
1,919
$
1,009
—
(130)
173
636
—
209
126
Asset retirement obligation - end of period
$
3,942
$
2,890
$
2,148
370
(1,024)
347
78
1,919
Note 8. Debt
Our credit facility consists of a $250.0 million senior secure revolving credit facility that expires in November 2018.
Borrowings under the facility are secured by liens on not less than 80% of our assets and the assets of our subsidiaries. We may
use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for
general partnership purposes and for funding distributions to our unitholders. At December 31, 2013, we had $112.0 million of
borrowings outstanding under the revolving credit facility. The facility requires us and our subsidiaries to maintain a leverage
ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX (as defined in the facility) of not more than 4.0 to 1.0,
and a current ratio of not less than 1.0 to 1.0.
During the 2013 borrowing base re-determinations, our borrowing base under the credit facility was reaffirmed at $130.0
million, in April, and it was increased from $130.0 million to $150.0 million in November 2013. Effective with this increase,
the maturity terms of our credit facility were extended to November 5, 2018 and the Bank of Nova Scotia was added to the
lender group. No other material terms of the original credit agreement were amended. During 2013, in connection with the
amendments to our credit facility, we incurred financing fees and expenses of approximately $0.4 million, which will be
amortized over the life of the credit facility. Such amortized expenses are recorded in "interest expense" on our consolidated
statements of operations.
Borrowings under the facility may not exceed our current borrowing base of $150.0 million. The borrowing base is
determined by the lenders based on the value of our proved oil and natural gas reserves using assumptions regarding future
prices, costs and other matters that may vary. The borrowing base is subject to scheduled redeterminations on or about April 30
and October 31 of each year with an additional redetermination during the period between each scheduled borrowing base
determination, either at our request or at the request of the lenders. An additional borrowing base redetermination may be made
at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge
contract.
Borrowings under the credit agreement bear interest at a floating rate based on, at our election: (i) the greater of the prime
rate of the Royal Bank of Canada, the federal funds effective rate plus 0.50%, and the one month adjusted London Interbank
Offered Rate ("LIBOR") plus 1.0% , all of which are subject to a margin that varies from 0.75% to 1.75% per annum according
to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in
effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base
usage. For the year ended December 31, 2013, the average effective rate was approximately 2.7%. The unused portion of the
borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base
usage.
The 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. If we fail to perform our obligations under
these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the
credit agreement, together with accrued interest could be declared immediately due and payable. We were in compliance with
these covenants as of and during the year ended December 31, 2013.
Note 9. Commitment and Contingencies
We entered into a service agreement with Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating will
provide certain services to us, our subsidiaries and our general partner, including management, administrative and operations
services, which include marketing, geological and engineering 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.
72
These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who
perform services for or on our behalf and other expenses allocated by Mid-Con Energy Operating to us.
We are party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of
management, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued,
insurance coverage or other indemnification arrangements will not have a material adverse effect on our financial position,
results of operations or cash flows.
Our general partner has entered into employment agreements with certain executive officers. The employment agreements
provide for a term that commenced on August 1, 2011 and expires on August 1, 2014, unless earlier terminated, with automatic
one-year renewal terms unless either we or the employee gives written notice of termination at least by February 1 preceding
any such August 1. Pursuant to the employment agreements, each employee will serve in his respective position with our
general partner, as set forth above, and has duties, responsibilities, and authority as the board of directors of our general partner
may specify from time to time, in roles consistent with such positions that are assigned to him. The agreement stipulates that if
there is a change of control, termination of employment with cause or without cause, or death of the executive certain payments
will be made to the executive officer. These payments, depending on the reason for termination, currently range from $1.6
million to $1.9 million, including the value of vesting of any outstanding units.
Note 10. Equity
Common Units
At December 31, 2013 and 2012, Partnership’s equity consisted of 19,319,362 and 18,990,849 common units,
respectively, representing approximately a 98% limited partnership interest in us.
In October 2012, we sold 4,600,000 common units to the public a price of $21.20 per common unit. 1,000,000 common
units were sold by us, and 3,600,000 common units were sold by Yorktown Energy Partners, VI, L.P., Yorktown Energy
Partners VII, L.P., and Yorktown Energy Partners VIII, L.P. Proceeds from our 1,000,000 common units offering, net of
underwriting discounts and expenses, were approximately $20.4 million. We did not receive any proceeds from the 3,600,000
common units sold by Yorktown.
Cash Distributions
We intend to continue to make regular cash distributions to unitholders on a quarterly basis, although there is no
assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements,
financial condition and other factors. Our credit facility prohibits us from making cash distributions if any potential default or
event of default, as defined in our credit facility, occurs or would result from the cash distribution.
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 a quarter after the payment of our expenses and the establishment of reserves for future capital
expenditures and operational needs, including cash from working capital borrowings. Our cash distribution policy reflects a
basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves,
rather than retaining it.
The following sets forth the distributions we paid during the years ended December 31, 2013 and 2012:
73
Date Paid
February 14, 2013
May 14, 2013
August 14, 2013
November 14, 2013
February 13, 2012
May 14, 2012
August 14, 2012
November 14, 2012
Period Covered
Distribution
Total
per Unit
Distribution
October 1, 2012 - December 31, 2012
$
0.495
$
January 1, 2013 - March 31, 2013
April 1, 2013 - June 30, 2013
July 1, 2013 - September 30, 2013
December 21, 2011 - December 31, 2012 $
January 1, 2012 - March 31, 2012
April 1, 2012 - June 30, 2012
July 1, 2012 - September 30, 2012
0.505
0.515
0.515
0.057
0.475
0.475
0.485
$
$
$
9,697
9,891
10,123
10,119
39,830
1,034 (1)
8,622
8,692
9,357
27,705
(1)
The distribution represented a proration of initial quarterly distribution of $0.475 per unit.
On January 22, 2014, the board of directors declared a quarterly cash distribution for the fourth quarter of 2013 of $0.515
per unit, which was paid on February 14, 2014 to unitholders of record at the close of business on February 7, 2014. The
aggregate amount of the distribution was approximately $10.3 million.
Allocations of Net Income (Loss)
Net income (loss) is allocated between our general partner and the limited partner unitholders in proportion to their pro
rata ownership during the period.
Note 11. Related Party Transactions
The following agreements were negotiated among affiliated parties and, consequently, are not the result of arm’s length
negotiations. The following is a description of those agreements that have been entered into with the affiliates of our general
partner and with our general partner.
Services Agreement
We are party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating
provides certain services to us, including management, administrative and operational services. The operational services
include marketing, geological and engineering 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. These
expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform
services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. During the years ended
December 31, 2013, 2012 and 2011, we reimbursed Mid-Con Energy Operating approximately $3.6 million, $2.9 million and
$0.2 million, respectively, for direct expenses.
Assignment, Bill of Sale and Conveyance Agreement
On December 20, 2011, we entered into an assignment, bill of sale and conveyance agreement pursuant to which J&A Oil
Company, a company controlled by Charles R. Olmstead and Jeffrey R. Olmstead, and Charles R. Olmstead, in his individual
capacity, contributed to the partnership certain working interests in the Cushing Field and J&A Oil Company contributed to the
partnership its interests in certain derivative contracts for aggregate consideration of approximately $6.0 million.
Contribution, Conveyance, Assumption and Merger Agreement
On December 20, 2011, we entered into a contribution, conveyance, assumption and merger agreement pursuant to which
Mid-Con Energy I, LLC and Mid-Con Energy II, LLC merged into our subsidiary, Mid-Con Energy Properties, and our general
partner made a contribution to us. The contribution, conveyance, assumption and merger agreement provided for the Founders,
Yorktown, our executive officers, employees and other individual entities, as the owners of Mid-Con Energy I, LLC and Mid-
Con Energy II, LLC, to receive consideration that included a combination of common units and cash from the proceeds of our
public offering and for our general partner to receive a 2.0% general partner interest in us. All of the transaction expenses
incurred in connection with these transactions were paid from proceeds of our Initial Public Offering.
74
Other Transactions with Related Persons
We, various third parties with an ownership interest in the same property and our affiliate, Mid-Con Energy Operating,
are party to standard oil and gas joint operating agreements, pursuant to which we and those third parties pay Mid-Con Energy
Operating overhead charges associated with operating our properties (commonly referred to as the Council of Petroleum
Accountants Societies, or COPAS, fee). We and those third parties will also pay Mid-Con Energy Operating for its direct and
indirect expenses that are chargeable to the wells under their respective operating agreements.
At December 31, 2013 and 2012, we had payables to Mid-Con Energy Operating of approximately $3.0 million which is
comprised of a joint interest billing payable of approximately $2.2 million and a payable for operating services of
approximately $0.8 million. These amounts are included in the Accounts payable-related parties in our consolidated balance
sheets.
Note 12. Credit Risk
Financial instruments which potentially subject us to credit risk consist principally of cash balances, accounts receivable
and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, may
exceed the federally insured limits. We have not experienced any significant losses from such investments. The percentage of
revenue derived by customers that accounted for approximately 10% or more of consolidated total revenues is presented below.
No other customer accounted for more than 10% of our consolidated total revenues for 2013, 2012 or 2011.
For the year ended December 31, 2013, sales of oil and natural gas to Enterprise Crude Oil, LLC (“Enterprise”),
Coffeyville Resources Refining & Marketing, LLC ("Coffeyville"), Valero Marketing & Supply Co. ("Valero"), and National
Cooperative Refinery Association (“National”) accounted for approximately 50%, 23%, 9%, and 8% respectively, of our total
sales revenues. These purchasers represent 46%, 30% , 7%, and 10%, respectively, of our outstanding oil and natural gas
accounts receivable at December 31, 2013.
For the year ended December 31, 2012, purchases by Enterprise Crude Oil, LLC (“Enterprise”), Vitol Inc. Crude Oil
Marketing (“Vitol”) and Sunoco Logistics accounted for 32%, 28%, and 21%, respectively of our total sales revenues. Vitol
represented 52% of our outstanding oil and natural gas accounts receivable at December 31, 2012. Enterprise and Sunoco
Logistics did not have any outstanding receivables at the December 31, 2012 because their contracts had expired during the
year 2012. We entered into an agreement with Enterprise beginning January 2013 to begin purchasing our oil in the Southern
Oklahoma core area.
For the year ended December 31, 2011 a subsidiary of Sunoco Logistics Partners L.P. (“Sunoco Logistics”), ScissorTail
Energy, LLC and Teppco Crude Oil, LLC accounted for 86%, 9% and 3%, respectively of our total sales revenues. These
purchasers represented 88%, 2% and 9%, respectively, of our outstanding oil and natural gas accounts receivable at
December 31, 2011.
We believe that the loss of any one purchaser would not have an adverse effect on our ability to sell its oil and gas
production because we believe market conditions are such that we could sell to other purchasers at market-based prices. We
have not experienced any significant losses due to uncollectible accounts receivable from these purchasers.
Note 13. Employee Benefit Plans
In 2011, our general partner adopted the Mid-Con Energy Partners, LP Long-Term Incentive Program which is intended
to promote the interests of the partnership by providing to employees, officers, consultants and directors of our general partner
and our other affiliates, including Mid-Con Energy Operating, grants of restricted units, phantom units, unit appreciation rights,
distribution equivalent rights, and other unit based awards to encourage superior performance, The Long-Term Incentive
Program is also intended to enhance the ability of the general partner and our other affiliates, including Mid-Con Energy
Operating, to attract and retain the services of individuals who are essential for the growth and profitability of the partnership
and to encourage them to devote their best efforts to advancing the business of the partnership.
The Long-Term Incentive Program is currently administered by a committee consisting of the Founders and approved by
the Board of Directors. Except as set forth 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. In determining whether to grant awards and the amount of any awards,
the committee takes into consideration discretionary factors such as the individual’s current and expected future performance,
level of responsibility, retention considerations and the total compensation package.
The type of awards that may be granted under the Long-Term Incentive Program are restricted units, phantom units, unit
options, unit appreciation rights, distribution equivalent rights and other unit-based awards. The maximum number of our
75
common units that are currently authorized to be awarded under the Plan is 1,764,000 units. As of December 31, 2013 there
were 1,041,638 units available for issuance.
Note 14. Income Taxes
We do not pay federal income taxes, as our profits or losses are reported to the taxing authorities by our individual
partners.
Note 15. Subsequent Events
On January 22, 2014, the board of directors declared a quarterly cash distribution for the fourth quarter of 2013 of $0.515
per unit, or $2.06 on an annualized basis, which was paid on February 14, 2014 to unitholders of record as of the close of
business on February 7, 2014. The aggregate amount of the distribution was approximately $10.3 million.
Also on January 22, 2014, the board of directors of our general partner authorized the issuance of 247,050 common units
to certain employees of our affiliates and certain directors and founders of our general partner.
On February 28, 2014, we entered into a definitive purchase and sale agreement (the “Purchase Agreement”) with one of
our Mid-Con Affiliates, Mid-Con Energy III, LLC to acquire multiple oil properties located in Cimarron, Love and Texas Counties,
Oklahoma and Potter County, Texas for an aggregate purchase price of approximately $41.0 million, subject to customary post-
closing purchase price adjustments (collectively, the “Acquisition”). The effective date of the Acquisition was January 1, 2014.
The Acquisition was closed on the same day of February 28, 2014. We paid the aggregate purchase price with (i) approximately
$7.0 million in cash, financed through borrowings under our revolving credit facility, and (ii) the issuance of 1,500,000 common
units representing limited partner interests in the Partnership, having an approximate value of $34.0 million. The value of the
common units issued as partial consideration for the Acquisition was based on a 2.5% discount to the trailing twenty day volume
weighted average price of the common units.
The terms of the Purchase Agreement were approved by the Conflicts Committee of the Board of Directors of the
General Partner (the “Conflicts Committee”). The Conflicts Committee, which is composed entirely of independent directors,
retained independent legal and financial counsel to assist it in evaluating and negotiating the Purchase Agreement and the
Acquisition.
76
Note 16. Supplementary Information
Quarterly data (unaudited)
Quarters Ended
March 31
June 30
September 30
December 31
(In thousands, except per unit amounts)
2013
Oil and natural gas sales
Net settlements on derivatives
Gain (loss) on unsettled derivatives, net
Total revenues and other
Total expenses (1)
Net income
Limited partners' interest in net income
Net income per limited partner unit (basic)
Net income per limited partner unit (diluted)
2012
Oil and natural gas sales
Net settlements on derivatives
Gain (loss) on unsettled derivatives, net
Total revenues and other
Total expenses (1)
Net income (loss)
Limited partners' interest in net income (loss)
Net income (loss) per limited partner unit (basic)
Net income (loss) per limited partner unit (diluted)
$
20,176
$
21,110
$
673
(1,793)
19,056
14,997
4,059
3,985
0.21
0.21
15,507
(134)
(4,773)
10,600
8,938
1,662
1,629
0.09
0.09
$
$
$
$
$
709
960
22,779
12,241
10,538
10,344
0.54
0.54
13,844
903
14,514
29,261
6,833
22,428
21,984
$
$
$
1.23
1.23
$
$
$
$
$
$
$
$
21,468
22,982
(1,293)
(5,501)
16,188
11,931
4,257
4,179
0.22
0.22
15,048
1,211
(6,103)
10,156
$
$
$
11,293
(1,137)
(1,115)
(0.06) $
(0.06) $
199
371
22,038
12,703
9,335
9,163
0.47
0.47
17,162
1,730
(1,634)
17,258
10,349
6,909
6,774
0.36
0.36
(1)
Includes the following expenses: lease operating, production taxes, dry holes and abandonments, geological and
geophysical, depreciation, depletion and amortization, accretion, and general and administrative.
Supplementary oil and natural gas activities
Property acquisition costs:
Proved
Unproved
Exploration
Development
Asset retirement obligations
Total costs incurred
Year Ended December 31,
2013
2012
2011
(in thousands)
$
28,057
$
48,578
$
15,729
—
—
22,287
879
—
—
21,639
679
—
—
30,754
686
$
51,223
$
70,896
$
47,169
Estimated proved oil and natural gas reserves (unaudited)
The proved oil and gas reserves for the years ended December 31, 2013, 2012, and 2011 were prepared by our reservoir
engineers and audited by Cawley, Gillespie & Associates, Inc., independent third party petroleum consultants. These reserve
estimates have been prepared in compliance with the rules of the SEC. We emphasize that reserve estimates are inherently
77
imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties.
Accordingly, the estimates are expected to change as future information becomes available. An analysis of the change in
estimated quantities of oil and gas reserves, all of which are located within the United States, are presented below for the
periods indicated:
Oil
(MBbls)
Gas
(MMcf)
MBoe (1)
Proved developed and undeveloped reserves:
As of December 31, 2010
Revisions of previous estimates
Extensions, discoveries and other additions
Purchases of minerals in place
Sales of minerals in place
Production
As of December 31, 2011
Revisions of previous estimates
Extensions, discoveries and other additions
Purchases of minerals in place
Production
As of December 31, 2012
Revisions of previous estimates
Extensions, discoveries and other additions
Purchases of minerals in place
Production
As of December 31, 2013
Proved developed reserves:
December 31, 2010
December 31, 2011
December 31, 2012
December 31, 2013
Proved undeveloped reserves:
December 31, 2010
December 31, 2011
December 31, 2012
December 31, 2013
7,007
740
1,704
971
(79)
(407)
9,936
(784)
1,572
3,028
(678)
13,074
264
76
1,207
(907)
13,714
3,601
6,835
8,727
10,397
3,406
3,101
4,347
3,317
1,346
(370)
—
140
(276)
(164)
676
(143)
—
18
(122)
429
827
—
193
(128)
1,321
1,346
676
429
1,321
—
—
—
—
7,231
678
1,704
994
(124)
(434)
10,049
(808)
1,572
3,031
(698)
13,146
401
76
1,239
(928)
13,934
3,825
6,948
8,799
10,617
3,406
3,101
4,347
3,317
(1)
Estimated quantities of oil and natural gas reserves in Mboe equivalents at a rate of six Mcf per Bbl.
The change in quantities of proved reserves from December 31, 2010 to December 31, 2011 is due to (i) increases in oil
prices during this time period, (ii) acquisitions of the War Party I and II Units in the Hugoton Basin, J&A Oil Company
interests in the Cushing Field, and third party interests in the Cleveland Field, (iii) infill drilling in our Ardmore West and Twin
Forks waterflood units which resulted in an upward revision of oil in place and therefore recoverable reserves, and
(iv) revisions of previous estimates for the balance of our properties.
The change in quantities of proved reserves from December 31, 2011 to December 31, 2012 is due to (i) the acquisitions
of additional interests in our Southern Oklahoma units; (ii) the acquisition of additional working interest in our War Party I and
II Units in the Hugoton Basin area; (iii), the acquisition of the Clawson Ranch Waterflood Unit in the Hugoton Basin area;, and
(iv) the acquisition of additional properties in the Northeastern Oklahoma area.
The change in quantities of proved reserves from December 31, 2012 to December 31, 2013 is due to the acquisitions of
additional interests in our Southern Oklahoma units and Northeastern Oklahoma properties and revisions on prior estimates.
78
Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of
variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results.
Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data
are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions
as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts
estimated.
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 gas reserves,
less future development, production, plugging and abandonment costs, discounted at the rate prescribed by the SEC. The
standardized measure of discounted future net cash 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 following assumptions have been made:
•
In the determination of future cash inflows, sales prices used for oil and natural gas for the years ended December 31,
2013, 2012 and 2011, were estimated using the average price during the 12-month period, determined as the unweighted
arithmetic average of the first-day-of-the-month price for each month in such period.
• Future costs of developing and producing the proved oil and 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, LP because we are a non-taxable entity.
• 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 the periods indicated:
Future cash inflows
Future production costs
Future development costs, including abandonment costs
Future net cash flow
10% discount for estimated timing of cash flow
Standardized measure of discounted cash flow
Year Ended December 31,
2013
2012
2011
(in thousands)
$
$
1,295,435
(542,389)
(49,458)
703,588
(312,325)
391,263
$
$
1,191,410
(417,362)
(47,490)
726,558
(323,136)
403,422
$
$
930,788
(297,490)
(34,504)
598,794
(270,563)
328,231
The prices utilized in calculating our total proved reserves were $96.78, $94.71, and $96.19 per Bbl of oil and $3.67,
$2.75 and $4.11 per MMBtu of natural gas for December 31, 2013, 2012, and 2011, respectively. These prices were adjusted by
lease for quality, transportation fees, location differentials, marketing bonuses or deductions or other factors affecting the price
received at the wellhead. Average adjusted prices used were $93.98, $91.03 and $93.20 per Bbl of oil and $5.00, $2.87 and
$7.04 per Mcf of natural gas for December 31, 2013, 2012 and 2011, respectively. Adjusted natural gas price includes the sale
of associated natural gas liquids. All wellhead prices are held flat over the life of the properties for all reserve categories.
79
Changes in the standardized measure of discounted future net cash flow relating to proved oil and gas reserves is
presented below for the periods indicated:
Standardized measure of discounted future net cash flow, beginning of
period
$
403,422
$
328,231
$
183,662
Year Ended December 31,
2013
2012
2011
Changes in the year resulting from:
Sales, less production costs
Revisions of previous quantity estimates
Extensions, discoveries and improved recovery
Net change in prices and production costs
Net change in income taxes
Changes in estimated future development costs
Previously estimated development costs incurred during the period
Purchases of minerals in place
Accretion of discount
Timing differences and other
Standardized measure of discounted future net cash flow, end of year
$
(65,553)
12,006
1,863
(28,324)
—
(17,155)
22,257
38,170
40,342
(15,765)
391,263
$
(48,648)
(26,796)
51,098
(15,328)
—
(11,515)
21,629
81,602
32,823
(9,674)
403,422
$
(27,671)
26,960
26,128
79,618
—
(30,521)
31,968
20,200
18,366
(479)
328,231
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROL AND PROCEDURES
Evaluation 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 financial officer (principal financial officer), the
effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act)
as of December 31, 2013. Our disclosure controls and procedures are designed to provide reasonable assurance that the
information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to
our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions
regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the
rules and forms of the SEC. Based on this evaluation, our chief executive officer and chief financial officer have concluded that
our disclosure controls and procedures were effective as of the end of the period covered by this Form 10-K.
Management’s Report on Internal Control over Financial Reporting
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and
maintaining adequate internal control over our financial reporting. Our internal control system was designed to provide
reasonable assurance to our Management and Directors regarding the preparation and fair presentation of published financial
statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may
become inadequate 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 1992
Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on this evaluation, management concluded that Mid-Con Energy Partners, L.P.’s internal control over
financial reporting was effective as of December 31, 2013.
80
/s/ Charles R. Olmstead
Charles R. Olmstead
Chief Executive Officer
March 5, 2014
/s/ Jeffrey R. Olmstead
Jeffrey R. Olmstead
President and Chief Financial Officer
As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth
company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. As an emerging growth company
we may take advantage of specified reduced reporting and other regulatory requirements for up to five years that are otherwise
applicable generally to public companies. As an emerging growth company we are taking the exemption from the auditor
attestation requirement on the effectiveness of our system of internal control over financial reporting.
Change in Internal Controls Over Financial Reporting
There 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 Exchange Act) that occurred during the period covered by this Form 10-K that have materially affected, or
are reasonably likely to materially affect, our internal control over 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 of the Sarbanes-Oxley Act of 2002, from time to time we have identified areas in need of improvement
and have taken remedial actions to strengthen the affected controls as appropriate. We make these and other changes to enhance
the effectiveness of our internal control over financial reporting, which do not have a material effect on our overall internal
control.
ITEM 9B. OTHER INFORMATION
None
81
PART III
ITEM 10. DIRECTORS, EXECUTIVES OFFICERS AND CORPORATE GOVERNANCE
As is the case with many publicly traded partnerships, we do not directly employ officers, directors or employees. Our
operations and activities are managed 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 owned and controlled by the Founders.
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, or directly or
indirectly participate in our management or operations. Further, our partnership agreement contains provisions that
substantially restrict the fiduciary duties that our general partner would otherwise owe to our unitholders under Delaware law.
The board of directors of our general partner has nine members. The NASDAQ listing rules do not require a listed limited
partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a
compensation committee or a nominating and corporate governance committee. We are, however, required to have an audit
committee of at least three members, all of whom are required to meet the independence and experience standards established
by the NASDAQ listing rules and SEC rules.
All of the executive officers of our general partner are also officers and/or directors of the Mid-Con Affiliates. The
executive officers of our general partner allocate their time between managing our business and affairs and the business and
affairs of the Mid-Con Affiliates. In addition, employees of Mid-Con Energy Operating provide management, administrative
and operational services to us pursuant to the services agreement, but they also provide these services to the Mid-Con
Affiliates.
Directors and Executive Officers
Each of the directors and officers, except Mr. Pekar, Mr. Wiggins and Mr. Ball, have served in their current position since
the Initial Public Offering. The following table sets forth certain information regarding the current directors and executive
officers of our general partner.
Name
S. Craig George
Charles R. “Randy” Olmstead
Jeffrey R. Olmstead
Michael L. Wiggins
David A. Culbertson
Nathan P. Pekar
Peter A. Leidel
Cameron O. Smith (i)
Robert W. Berry (i)
Peter Adamson III (i)
C. Fred Ball Jr. (ii)
Age
Position with Mid-Con Energy GP, LLC
61 Executive Chairman of the Board
65 Chief Executive Officer and Director
37 President, Chief Financial Officer and Director
57 Executive Vice President, Chief Engineer and Director
48 Vice President and Chief Accounting Officer
38 Vice President, General Counsel and Secretary
57 Director
63 Director
90 Director
72 Director
69 Director
(i)
(ii)
Member of the audit committee and the conflicts committee.
Member of the audit committee.
The members of our general partner's board of directors are appointed for one-year terms by the Founders and hold office
until the earlier of their death, resignation, removal or disqualification or until their successors have been appointed and
qualified. The executive officers of our general partner serve at the discretion of the board of directors. All of our general
partner's executive officers also serve as executive officers of the Mid-Con Affiliates. Charles R. Olmstead and Jeffrey R.
Olmstead are father and son, respectively. There are no other family relationships among our general partner's executive
officers and directors.
S. Craig George serves as Executive Chairman of the board of directors of our general partner. Mr. George has been a
member of the board of directors of Mid-Con Energy III, LLC, Mid-Con Energy IV, LLC and Mid-Con Energy Operating since
82
June 2011. Mr. George was a member of the board of directors of Mid-Con Energy I, LLC and Mid-Con Energy Operating
since 2004 and of Mid-Con Energy II, LLC from its formation in 2009 until both entities were merged into us in December
2011. From 1991 to 2004, Mr. George served in various executive positions at Vintage Petroleum, Inc., including President,
Chief Executive Officer and as a member of the board of directors. In 1981, Mr. George joined Santa Fe Minerals, Inc. where
he served until 1991 in executive positions including Vice President of Domestic Operations and Vice President-International.
From 1975-1981, Mr. George held engineering and management positions with Amoco Production Company. Mr. George is a
graduate of Missouri University of Science and Technology, with a Bachelor of Science degree in Mechanical Engineering, and
of Aquinas Institute, with a Master of Arts in Theology. Over the course of his lengthy career in the oil and gas industry,
Mr. George has gained extensive management and operational experience and has demonstrated a strong record of leadership,
strategic vision and risk management. In light of Mr. George’s extensive industry and managerial experience and knowledge,
the Founders have concluded that Mr. George should continue to serve as a member of our board of directors.
Charles R. “Randy” Olmstead serves as Chief Executive Officer and as a member of the board of directors of our general
partner. Mr. Olmstead has been Chief Executive Officer and Chairman of the board of directors of Mid-Con Energy III, LLC
and Mid-Con Energy IV, LLC since June 2011. Mr. Olmstead served as President, Chief Financial Officer and Chairman of the
board of directors of Mid-Con Energy I, LLC from its formation in 2004 and of Mid-Con Energy II, LLC from its formation in
2009 until both entities were merged into us in December 2011. He has been President, Chief Financial Officer and Chairman
of the board of directors of Mid-Con Energy Operating since its incorporation in 1986. Prior to that, Mr. Olmstead was general
manager for LB Jackson Drilling Company from 1978 to 1980 and worked in public accounting for Touche Ross & Co. from
1974 to 1978 as an oil and gas tax consultant. Mr. Olmstead graduated from the University of Oklahoma with Bachelors of
Business Administration degrees in finance and accounting before serving three years in the US Navy. Mr. Olmstead’s
extensive management and operational experience in the oil and gas industry, along with his leadership skills, provides a
critical resource to the board of directors. Because of Mr. Olmstead’s extensive management, operational experience and
leadership skills, the Founders have concluded that Mr. Olmstead should continue to serve as a member of our board of
directors.
Jeffrey R. Olmstead serves as President, Chief Financial Officer and as a member of the board of directors of our general
partner. Mr. Olmstead has been a member of the board of directors of Mid-Con Energy III, LLC and President, Chief Financial
Officer and a member of the board of directors of Mid-Con Energy IV, LLC since June 2011. Mr. Olmstead was a member of
the board of directors of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC from 2007 until both entities were merged into
us in December 2011. Mr. Olmstead previously served as Chief Financial Officer and Vice President of Primexx Energy
Partners, Ltd., a privately held exploration and production company, from May 2010 until July 2011. From August 2006 until
May 2010, Mr. Olmstead served as an Assistant Vice President at Bank of Texas/Bank of Oklahoma. Mr. Olmstead is a
graduate of Vanderbilt University, with a Bachelor of Engineering degree in Electrical Engineering and Math, and of the Owen
School of Business at Vanderbilt University, with a Master of Business Administration. Mr. Olmstead’s knowledge of the oil
and gas industry and his finance background will provide a critical resource to our board of directors, and the Founders have
concluded that he should continue to serve as a director.
Michael L. Wiggins serves as Executive Vice President, Chief Engineer, and member of the board of directors of our
general partner. Dr. Wiggins became an officer of our general partner in March 2013 and was named to the board of directors in
April 2013. Prior to joining us, Dr. Wiggins served as President of William M. Cobb & Associates, Inc. where his expertise
included reservoir studies, oil and gas reserve evaluations and audits, improved recovery design, educational courses, and
litigation support including expert witness services. He has over 30 years of professional experience in academia and the
upstream oil and gas industry including drilling, production, and reservoir engineering dating to 1979. Dr. Wiggins is a
Distinguished Member of the Society of Petroleum Engineers ("SPE") and has served on the SPE Board of Directors. Dr.
Wiggins earned his bachelor, master, and doctoral degrees in Petroleum Engineering from Texas A&M University. Dr. Wiggins
is a registered professional engineer in the states of Texas and Oklahoma. Dr. Wiggins knowledge of the oil and gas industry
and his expertise in reservoir studies will provide a critical resource to our board of directors, and the Founders have concluded
that he should continue to serve as a director.
David A. Culbertson serves as Vice President and Chief Accounting Officer of our general partner. Mr. Culbertson has
served as Controller of Mid-Con Energy I, LLC from 2006 and of Mid-Con Energy II, LLC from its formation in 2009 until
both entities were merged into us in December 2011. He has also supervised the accounting function for affiliates of our
predecessor. Prior to joining us in 2006, Mr. Culbertson served in various accounting positions with Vintage Petroleum from
2003-2006, the Williams Companies from 1999-2003 and Samson Resources from 1989-1999. Mr. Culbertson is a graduate of
Oklahoma State University, with a Bachelor of Business Administration degree in accounting, and of the University of Tulsa,
with a Master of Business Administration. He is a Certified Public Accountant.
Nathan P. Pekar serves as Vice President of Business Development, General Counsel and Secretary of our general
partner. Mr. Pekar became an officer of our general partner in April 2012. Prior to joining us, Mr. Pekar served as General
83
Counsel and Business Development Manager with Matador Resources Company, from 2007-2012. Prior to this, Mr. Pekar was
in private practice from 2003 to 2007. Mr. Pekar is a graduate of the University of Texas at Austin, with a Bachelor of Business
Administration degree in Finance, and of Southern Methodist University School of Law, with a Juris Doctor degree. He is a
licensed attorney in the State of Texas.
Peter A. Leidel serves as a member of the board of directors of our general partner. Mr. Leidel is a founder and principal
of Yorktown Partners LLC, which was established in September 1990. Yorktown Partners LLC is the manager of private
investment partnerships that invest in the energy industry. Mr. Leidel has been a member of the board of directors of Mid-Con
Energy III, LLC, Mid-Con Energy IV, LLC and Mid-Con Energy Operating since June 2011. Mr. Leidel was a member of the
board of directors of Mid-Con Energy I, LLC from its formation in 2004 and of Mid-Con Energy II, LLC from its formation in
2009 until both entities were merged into us in December 2011. Previously, he was a partner of Dillon, Read & Co. Inc., held
corporate treasury positions at Mobil Corporation and worked for KPMG and for the U.S. Patent and Trademark Office.
Mr. Leidel is a director of certain non-public companies in the energy industry in which Yorktown holds equity interests.
Mr. Leidel is a graduate of the University of Wisconsin, with a Bachelor of Business Administration degree in accounting and
of the Wharton School at the University of Pennsylvania, with a Master of Business Administration. In light of Mr. Leidel’s
extensive private experience within the energy sector, the Founders have concluded that he should continue to serve as a
member of our board of directors.
Cameron O. Smith serves as a member of the board of directors of our general partner and is also chairman of the
conflicts committee. Mr. Smith founded and from 1992 to 2008, served as a Senior Managing Director of COSCO Capital
Management LLC, an investment bank focused on private oil and gas corporate and project financing until Rodman &
Renshaw, LLC, a full service investment bank, purchased the business and assets of COSCO Capital Management LLC. From
2008 until December 2009, Mr. Smith served as a Senior Managing Director of Rodman & Renshaw, LLC and as Head of The
Rodman Energy Group, a sector vertical within Rodman & Renshaw, LLC. Mr. Smith retired from The Rodman Energy Group
in December 2009. Mr. Smith founded and ran Taconic Petroleum Corporation, an exploration company headquartered in
Tulsa, Oklahoma from 1978 to 1991. Mr. Smith served as exploration geologist, officer and director of several private family
and public client companies from 1975 to 1985. Mr. Smith attended Princeton University receiving an A.B. in Art History in
1972 and Pennsylvania State University receiving a Master of Science in Geology in 1975. As a result of Mr. Smith’s extensive
knowledge of the oil and natural gas industry, along with his expertise in investment banking, the Founders have concluded that
he should continue to serve as a member of our board of directors.
Robert W. Berry serves as a member of the board of directors of our general partner. Mr. Berry is founder, Chief
Executive Officer and President of Robert W. Berry, Inc., Empress Gas Corp. Ltd., R.W. Berry Canada, Inc. and Berry
Ventures, Inc. which produce oil and gas in Oklahoma, Texas, Arkansas, North Dakota and Canada, and has served in these
positions for more than the past five years. Mr. Berry has drilled and discovered numerous oil fields in Texas, North Dakota and
Canada since working for Amerada Petroleum Corporation as a geologist. Mr. Berry graduated from the University of
Oklahoma with a Bachelor of Science degree in Geology. Because of the technical knowledge and experience he has garnered
over the last 60 years in the oil and natural gas business, the Founders have concluded that he should continue to serve as a
member of our board of directors.
Peter Adamson III serves as a member of the board of directors of our general partner and is also chairman of the audit
committee. Mr. Adamson is currently managing member of Autumn Glory Partners, LLC, a private consulting firm. Prior to
Autumn Glory Partners, LLC, Mr. Adamson was a founder of Adams Hall Asset Management LLC, a Tulsa, Oklahoma based
registered investment advisor with over $1 billion under management and remains a consultant. Prior to forming Adams Hall in
1997, Mr. Adamson was an owner and principal of Houchin, Adamson & Co., Inc., a registered broker-dealer formed in 1980.
Mr. Adamson is founding co-investor and advisor to Horizon Well Logging, a leading provider of geological field services.
Mr. Adamson serves on the advisory board of the Michel F. Price College of Business at the University of Oklahoma and serves
on the University of Oklahoma asset oversight committee. Mr. Adamson received his Bachelor of Business Administration
degree in accounting from the University of Oklahoma. As a result of Mr. Adamson’s knowledge of finance and accounting the
Founders have concluded that he provides a critical resource and skill set to our board of directors and the Founders have
concluded that he should continue to serve as a member of our board of directors.
C. Fred Ball, Jr. currently serves as Senior Chairman of the Board for Bank of Texas, a division of BOK Financial
Corporation. During his 16 year tenure at Bank of Texas, Mr. Ball has been elected to various executive positions including
President, Chief Executive Officer and Chairman. Prior to Bank of Texas, he served as President of Comerica Securities, Inc., a
subsidiary of Comerica Incorporated in Detroit. Mr. Ball currently serves on the Board of Directors for BOK Financial
Corporation, the National Teachers Associates Life Insurance Company, where he is also a member of the audit committee, and
at Southern Methodist University, where he resides on both the Executive Board of the Edwin L. Cox School of Business and
the Executive Board of the Lyle School of Engineering. Mr. Ball earned his Bachelor of Science in Engineering and Master of
84
Business Administration from Southern Methodist University. Mr. Ball’s knowledge of finance and banking will provide a
critical resource to our board of directors, and the Founders have concluded that he should continue to serve as a director.
Committees of the Board of Directors
Mid-Con Energy GP, LLC’s board of directors has an audit committee and a conflicts committee. The Audit Committee
charter is posted under the “Investor Relations” section of our website at www.midconenergypartners.com. We do not have a
compensation committee. The NASDAQ listing rules do not require a listed limited partnership to establish a compensation
committee or a nominating and corporate governance committee.
We are, however, required to have an audit committee, a majority of whose members are required to be “independent”
under NASDAQ standards. Our board of directors or an appointed committee, currently comprised of the Founders, approve
equity grants to directors and employees.
Audit Committee
The audit committee consists of Messrs. Berry, Smith, Adamson and Ball. Our board of directors have affirmatively
determined that each member of the audit committee meets the independence and experience standards established by the
NASDAQ listing rules and the rules of the SEC. Our board of directors has also reviewed the financial expertise of
Mr. Adamson and affirmatively determined that he is an “audit committee financial expert,” as determined by the rules of the
SEC. Our board of directors 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 secretary of Mid-Con Energy GP, LLC.
The audit committee held five meetings in 2013. The audit committee assists the board of directors in its oversight of the
integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and
controls. The audit committee has the sole authority to (1) retain and terminate our independent registered public accounting
firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public
accounting firm and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered
public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our
independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access
to the audit committee and our management, as necessary.
Conflicts Committee
The conflicts committee consists of Messrs. Berry, Smith and Adamson, all of whom meet the independence standards
established by the NASDAQ listing rules 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 if the resolution of such conflict is “fair and reasonable” for
our unitholders. In making such determination, the conflicts committee has the authority to engage advisors to assist it in
carrying its duties. The conflicts committee held no meetings in 2013.
Board Leadership Structure and Role in Risk Oversight
Leadership of our general partner's board of directors is vested in a Chairman of the Board. Although our Chief Executive
Officer currently does not serve as Chairman of the Board of Directors of our general partner, we currently have no policy
prohibiting our current or any future chief executive officer from serving as Chairman of the Board. The board of directors, in
recognizing the importance of its ability to operate independently, determined that separating the roles of Chairman of the
Board and Chief Executive Officer is advantageous for us and our unitholders at this time. Our general partner's board of
directors has also determined that having the Chief Executive Officer serve as a director will enhance understanding and
communication between management and the board of directors, allows for better comprehension and evaluation of our
operations, and ultimately improves the ability of the board of directors to perform its oversight role.
The management of enterprise-level risk is the process of identifying, managing and monitoring of events that present
opportunities and risks with respect to the creation of value for our unitholders. The board of directors of our general partner
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 the board of
directors at least once every year.
Non-Management Executive Sessions and Unitholder Communications
NASDAQ listing standards require regular executive sessions of the non-management directors of a listed company, and
an executive session for independent directors at least once a year. At each quarterly meeting of our general partner's board of
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directors, all of the directors meet in an executive session. At least annually, our independent 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, 2501 North Harwood Street, Suite 2410, Dallas, Texas 75201. Such communications should specify the intended recipient
or recipients. Commercial solicitations or communications will not be forwarded.
Meetings and Other Information
The board of directors held five meetings in 2013.
Our partnership agreement provides that the general partner manages and operates us and 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 Compliance
Section 16(a) of the Exchange Act requires executive officers and directors of our general partner and persons who
beneficially own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act to file
certain reports with the SEC and the NASDAQ concerning their beneficial ownership of such securities. Based solely on a
review of the copies of reports on Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from
the executive officers and directors of our general partner, we believe that all filing requirements applicable to the officers and
directors of our general partner and greater than 10% unitholders were complied with for the fiscal year ended December 31,
2013.
Code of Ethics
The governance of Mid-Con Energy GP, LLC is, in effect, the governance of our partnership, subject in all cases to any
specific unitholder rights contained in our partnership agreement.
Mid-Con Energy GP, LLC has adopted a Code of Business Conduct that applies to all officers, directors and employees of
Mid-Con Energy GP, LLC and its affiliates. A copy of our Code of Business Conduct is available on our website at
www.midconenergypartners.com. We will provide a copy of our code of ethics to any person, without charge, upon request to
Mid-Con Energy GP, LLC, 2501 North Harwood Street, Suite 2410, Dallas, Texas 75201, Attn: Investor Relations.
Web Access
We provide access through our website at www.midconenergypartners.com to current information relating to partnership
governance, including our Audit Committee Charter, our Code of Business Conduct and other matters impacting our
governance principles. You may access copies of each of these documents from our website. You may also contact the office of
the secretary of our general partner for printed copies of these documents free of charge. Our website and any contents thereof
are not incorporated by reference into this document.
Communication with Directors
Our board of directors believes that it is management’s role to speak for the partnership. Our board of directors also
believes that any communications between members of the board of directors and interested parties, including unitholders,
should be conducted with the knowledge of our executive chairman, president and chief executive officer. Interested parties,
including unitholders, may contact one or more members of our board of directors, including non-management directors and
non-management directors as a group, by writing to the director or directors in care of the secretary of our general partner at
our principal executive offices. A communication received from an interested party or unitholder will be promptly forwarded to
the director or directors to whom the communication is addressed. A copy of the communication will also be provided to our
executive chairman and chief executive 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 COMPENSATION
Compensation Discussion and Analysis
General
86
We do not directly employ any of the persons responsible for managing our business. Our general partner’s executive
officers manage and operate our business as part of the services provided by Mid-Con Energy Operating to our general partner
under the services agreement. All of our general partner’s executive officers and other employees necessary to operate our
business are employed and compensated by Mid-Con Energy Operating, subject to reimbursement by our general partner. The
compensation for all of our executive officers is indirectly paid by us to the extent provided for in the partnership agreement
because we reimburse our general partner for payments it makes to Mid-Con Energy Operating.
Compensation Committee Report
The NASDAQ listing rules do not require a listed limited partnership to establish a compensation committee, and we do
not have a compensation committee. The board of directors of our general partner performs the functions of a compensation
committee, and although the board of directors of our general partner does not currently intend to establish a compensation
committee, it may do so in the future.
The board of directors of our general partner has reviewed and discussed with management the Compensation Discussion
and Analysis, or CD&A, set forth below. Based on this review and discussion, the board of directors determined that the CD&A
be included in this Annual Report on Form 10-K for the year ended December 31, 2013.
Submitted by:
S. Craig George
Charles R. “Randy” Olmstead
Jeffrey R. Olmstead
Michael L. Wiggins
Peter A. Leidel
Cameron O. Smith
Robert W. Berry
Peter Adamson III
C. Fred Ball Jr.
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this
Annual Report on Form 10-K into 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 specifically incorporate this information by reference, and shall not otherwise be
deemed filed under those Acts.
Objectives of Our Compensation Program
Our executive compensation program is intended to align the interests of our management team with those of our
unitholders by motivating our executive officers to achieve strong financial and operating results for us, which we believe
closely correlate to long-term unitholder value. In addition, our program is designed to achieve the following objectives:
•
•
•
attract, retain and reward talented executive officers by providing total compensation competitive with that of other
executive officers employed 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 our performance; and
encourage the long-term commitment of our executive officers to us and our unitholders’ long-term interests.
Elements of Our Compensation Program and Why We Pay Each Element
To 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 four elements:
•
•
•
•
base salary;
discretionary cash bonus;
long-term equity-based compensation; and
benefits.
87
We and our general partner were formed in July 2011; therefore, we incurred no cost or liability with respect to the
compensation of our executive officers. Accordingly, we are not presenting any compensation information for historical
periods.
The Founders, as the controlling 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 incentive program are also administered by the
Founders.
Our general partner also grants equity-based awards to our executive officers pursuant to a long-term incentive program
described below. Incentive compensation in respect of services provided to us is not tied in any way to the performance of
entities other than our partnership. Specifically, any performance 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 Operating employees 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 or direct 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 plans primarily reward longevity rather than performance. Mid-Con Energy Operating provides a basic
benefits package to all its employees, which includes a 401(k) plan and health, and basic term life insurance, and personal
accident and long-term disability coverage. Employees provided to us under the services agreement will be entitled to the same
basic benefits.
Employment Agreements
Our general partner has entered into employment agreements with each of the following named employees of our general
partner: Charles R. Olmstead, Chief Executive Officer; Jeffrey R. Olmstead, President and Chief Financial Officer; and S.
Craig George, Executive Chairman of the Board of our general partner.
The employment agreements provide for a term that commenced on August 1, 2011 and expires on August 1, 2014, unless
earlier terminated, with automatic one-year renewal terms unless either we or the employee gives written notice of termination
at least by February 1 preceding any such August 1. Effective January 29, 2014, the employment agreement for S.Craig George
was amended to extend the written notice deadline from February 1 to May 1, all other terms and conditions of the agreement
remained the same. Pursuant to the employment agreements, each employee will serve in his respective position with our
general partner, as set forth above, and has duties, responsibilities, and authority as the board of directors 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 the executive’s termination. This restriction continues
during the term of and for twelve months following termination of the executive’s employment, and also for twelve months
following the termination of the solicited employee’s employment. The non-solicitation provisions also prohibit an executive
from soliciting our customers during the term of and for twelve months following termination of the executive’s employment.
The non-competition provisions prohibit the executive from competing with us during the term of the executive’s employment
and for a period during which severance payments are being made 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 Program
Our Long-Term Incentive Program which is intended to promote the interests of the partnership by providing to
employees, officers, consultants and directors of our general partner and our other affiliates, including Mid-Con Energy
Operating, grants of restricted units, phantom units, unit appreciation rights, distribution equivalent rights, and other unit based
awards to encourage superior performance, The Long-Term Incentive Program is also intended to enhance the ability of the
general partner and our other affiliates, including Mid-Con Energy Operating, to attract and retain the services of individuals
who are essential for the growth and profitability of the partnership and to encourage them to devote their best efforts to
advancing the business of the partnership.
The Long-Term Incentive Program is currently administered by a committee consisting of the Founders and approved by
the Board of Directors. Except as set forth in the employment agreements of the executive officers of our general partner, we
88
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. In determining whether to grant awards and the amount of any awards,
the committee takes into consideration discretionary factors such as the individual’s current and expected future performance,
level of responsibility, retention considerations and the total compensation package.
The type of awards that may be granted under the Long-Term Incentive Program are restricted units, phantom units, unit
options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The maximum number
of our common units that are currently authorized to be awarded under the Plan is 1,764,000 million units. As of December 31,
2013 there were 1,041,638 units available for issuance.
Equity Compensation Plan Information:
Plan category
Equity compensation plans approved by
security holders
Equity compensation plans not approved
by security holders
Total
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights
(a)
Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)
Number of securities remaining available
for future issuance under equity
compensation plans (excluding securities
reflected in column (a))
(c)
—
—
—
—
—
—
1,041,638 common units
—
1,041,638 common units
The plan administrator may terminate or amend the Plan at any time with respect to any units for which a grant has not
yet been made. The plan administrator also has the right to alter or amend the Plan or any part of the Plan from time to time,
including increasing the number of units that may be granted subject to the requirements of the exchange upon which the
common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce
the rights or benefits of the participant without the consent of the participant. The Plan will expire on the earliest to occur of
(i) the date on which all common units available 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 Plan), any change in applicable law or regulation affecting the Plan or
awards thereunder, or any change in accounting principles affecting the financial statements of our general partner, the plan
administrator, in an attempt to prevent dilution or enlargement of any benefits available under the Plan 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 by the plan administrator, (iv) be assumed by the successor or survivor entity or be exchanged for
similar options, rights or awards covering the equity of such successor 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 or
property 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 determined by the plan administrator in the terms of the relevant award agreement or employment agreement.
Common units to be delivered pursuant to awards under the Plan may be common units already owned by our general
partner 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 issue new common units upon the grant, vesting or payment of awards under the Plan, the total number
of common units outstanding will increase, 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 awards settled in cash, our general partner will be entitled to
reimbursement by us for the amount of the cash settlement.
Short-Term Incentive Payments
The performance criteria for the short-term incentive plan for 2011 included 50% of the target bonus earned upon the
successful completion of the Initial Public Offering and 50% earned upon successful completion of the requirements allowing
common units issued to the Founders in conjunction with the Initial Public Offering that will initially be restricted from trading
to no longer be so restricted. The performance criteria for the short-term incentive plan for 2012 and future years include 50%
of the target bonus earned for meeting initial quarterly distribution goals, 20% earned for generating an increase in the amount
of distributions from the preceding year, 20% earned for generating additions of new reserves and growth of distributions based
89
on aggregate acquisitions of 10% growth, and 10% earned for overall performance as determined by our board. We do not
provide perquisites to the named executive officers.
Summary Compensation Table
The following table sets forth certain information with respect to compensation of our named executive officers for
services rendered in all capacities to us and our subsidiaries for the years ended December 31, 2013, 2012 and 2011. All of
these employees are paid by Mid-Con Energy Operating. We reimburse Mid-Con Energy Operating for a portion of their
compensation according to the services agreement entered between us and Mid-Con Energy Operating. There was not a service
agreement in place prior to December 2011; therefore, no salaries were allocated prior to December 2011.
Name and Principal Position
Charles R. Olmstead
Chief Executive Officer
Year
2013
2012
2011
$
185,489
$ 266,210
$ 1,120,500
$
186,292
15,361
— 1,275,000
—
—
Salary
Bonus
Unit Awards
Compensation
Total
S. Craig George
2013
$
263,489
$ 321,735
$ 1,120,500
$
Executive Chairman of the Board
Jeffrey R. Olmstead
President, Chief Financial Officer
Michael L. Wiggins
Executive Vice President, Chief Engineer
2012
2011
2013
2012
2011
2013
2012
2011
236,897
17,270
— 1,275,000
—
—
$
328,264
$ 297,935
$ 1,120,500
$
324,763
27,024
— 1,275,000
—
—
$
131,909
$
— $
248,900
$
— $
378,809
—
—
—
—
—
—
—
—
—
—
— $ 1,572,199
— 1,461,292
—
15,361
— $ 1,705,724
— 1,511,897
—
17,270
— $ 1,746,699
— 1,599,763
—
27,024
Nathan P. Pekar
Vice President, General Counsel
2013
$
201,656
$ 64,417
$
89,640
$
— $
355,713
2012
2011
167,443
—
—
—
385,045
—
—
—
552,488
—
Grants of Plan-Based Awards
The following table sets forth certain information with respect to grants of performance units to our named executive
officers in 2013. There were no grants of non-equity incentives or option awards.
Name
Charles R. Olmstead
S. Craig George
Jeffrey R. Olmstead
Michael L. Wiggins
Nathan P. Pekar
Grant Date
Unit
Awards
Grant Date Fair Value of
Unit Awards
1/31/2013
1/31/2013
1/31/2013
7/31/2013
1/31/2013
50,000
$
50,000
50,000
10,000
4,000
1,120,500
1,120,500
1,120,500
248,900
89,640
Outstanding Equity Awards at Fiscal Year End
The following table sets forth certain information with respect to outstanding equity awards at December 31, 2013.
90
Name
Nathan P. Pekar
Number of Units That
Have
Not Yet Vested
Market Value of
Units
That Have Not
Yet
Vested (1)
6,666 (2) $
149,318 (1)
(1)
(2)
Based on the closing price of our common units when the units were awarded at July 31, 2012.
These restricted units vest 33% each year beginning July 31, 2013.
Potential Post-Employment Payments and Payments upon a Change in Control
Payments Made Upon Any Termination – Regardless of the manner in which a named executive officer’s employment
terminates, he is entitled to receive amounts earned during his term of employment. Such amounts include:
•
•
•
•
accrued but unpaid base salary;
accrued but unpaid vacation pay;
any unreimbursed business expenses; and
any accrued benefits.
Payments Made Upon Termination Without “Cause” or For “Good Reason” – Effective August 2011, we entered into
employment agreements with each of S. Craig George, Charles R. Olmstead, and Jeffrey R. Olmstead. In the event of the
termination of any of these named executive officers without “cause” or for “good reason” (each as defined in the employment
agreements), if the named executive officer executes and does not revoke a general release of claims, in addition to the items
identified above, such named executive officer will be entitled to:
•
•
•
•
•
payment of base salary, as in effect immediately prior to termination, multiplied by the greater of the number of
years remaining in the employment period and one;
a lump sum payment to compensate the named executive officer for COBRA health-care coverage for the named
executive officer and the named executive officer’s dependents (if applicable);
accelerated vesting and conversion of any units which may have been awarded to the named executive officer
through our long-term incentive program;
payment of an amount equal to the lesser of the “target annual bonus” (as defined in the employment agreements)
and the average of the previous two annual bonuses paid to the named executive officer multiplied by the greater of
the number of years remaining in the employment period and one; and
payment of any unpaid annual bonus that would have become payable to the named executive officer in respect of
any calendar year that ends on or before the date of termination had the named executive officer remained
employed throughout the payment date of such annual bonus.
Payments Made Upon Death or Disability – In the event of the death or disability of one of these named executive
officers, if the officer or his estate executes and does not revoke a general release of claims, in addition to the benefits listed
under the heading “Payments Made Upon Any Termination” above, the officer or his estate will be entitled to:
•
•
•
•
•
accelerated vesting and conversion of any units which may have been awarded to the officer through our long-term
incentive program, in accordance with the terms of the applicable award agreement;
a lump sum payment to compensate the officer or the officer’s estate for COBRA health-care coverage for the
officer (if living) and the officer’s dependents (if applicable);
a payment equal to the product of the officer’s base salary as in effect immediately prior to the date of termination
multiplied by one;
payment of any unpaid annual bonus that would have become payable to the officer in respect of any calendar year
that ends on or before the date of termination had the officer remained employed through the payment date of such
annual bonus; and
payment of the target annual bonus for the year in which the officer’s separation from service occurs.
Payments Made Upon a Change in Control – Each employment agreement has an initial three-year term and is
automatically extended in one-year increments after the expiration of the initial term unless we provide written
91
notice of non-renewal to the officer, or the officer provides written notice of non-renewal to us, by at least
February 1 preceding the August 1 renewal date. If, during the period beginning sixty days prior to and ending two
years immediately following a “change in control,” either we terminate the officer’s employment without “cause,”
the officer’s death occurs, the officer becomes disabled or the officer terminates his employment for “good reason,”
then in addition to the benefits listed under the heading “Payments Made Upon Any Termination,” the officer will
be entitled to:
•
•
•
•
•
payment of base salary, as in effect immediately prior to termination, multiplied by two;
a lump sum payment to compensate the officer for COBRA health-care coverage for the named executive officer
and the officer’s dependents (if applicable);
accelerated vesting and conversion of any units which may have been awarded to the officer through our long-term
incentive program;
payment of an amount equal to the lesser of the “target annual bonus” (as defined in the employment agreements)
and the average of the previous two annual bonuses paid to the officer multiplied by two; and
payment of any unpaid annual bonus that would have become payable to the officer in respect of any calendar year
that ends on or before the date of termination had the officer remained employed throughout the payment date of
such annual bonus.
Additionally, if a change in control occurs during the employment period, certain equity-based awards held by the officers,
to the extent not previously vested and converted into common units, will vest in full upon such change in control
and will be settled in common units in accordance with the applicable award agreements. Relative to our overall
value, we believe the potential benefits payable upon a change in control under these agreements are comparatively
minor.
For the purposes of these agreements, a “change in control” generally means any of the following events:
•
•
•
•
•
any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d) of the Exchange
Act, other than certain of our affiliated entities, shall become the beneficial owner, directly or indirectly, by way of
merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power
of the equity interests in us;
a plan of complete liquidation, in one or a series of transactions, is approved;
the sale or other disposition by us of all or substantially all of our assets in one or more transactions to any person
other than certain of our affiliated entities;
a transaction resulting in a person other than us or one of certain of our affiliated entities being our general partner;
or
any time at which individuals who, as of October 31, 2011, constitute our Board of Directors (the “Incumbent
Board”) cease for any reason to constitute at least a majority of our Board; provided, however, that any individual
becoming a director subsequent to October 31, 2011, whose election, or nomination for election by our unitholders
was approved by a vote of at least a majority of the directors then comprising the Incumbent Board or whose
membership was required by any employment agreement with us will be considered as though such individuals
were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial
assumption of office occurs as the result of an actual or threatened election contest with respect to the election or
removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a person
other than the Incumbent Board.
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 the officer by the CEO which specifically identifies the
manner in which the CEO believes that the officer has not substantially performed the officer’s duties and the officer is given a
reasonable opportunity of not more than twenty business days to cure any such failure to substantially perform; the willful
engaging by the officer in illegal conduct or gross misconduct, including without limitation a material breach of the our Code
of Business Conduct or a material breach of 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 all requirements under the Sarbanes-Oxley Act, in each
case which is materially and demonstrably injurious to us; or any act of fraud, or material embezzlement or 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 the officer’s admission in any court, or conviction, or plea of nolo contendere, of a felony involving moral
92
turpitude, fraud, or material embezzlement, material theft or material misrepresentation, in each case, against or affecting us.
The CEO’s determination of materiality of any embezzlement, theft, or misrepresentation, 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: (i) a material diminution in the officer’s base salary; a material diminution in the officer’s authority, duties, or
responsibilities; a material diminution in the budget over which 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 his employment 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 incremental compensation due to each named executive officer subject to an employment agreement in the event of
such executive’s termination of employment upon death, disability or retirement, termination of employment without cause or
termination of employment without cause or with good reason within three years following a change in control. The amounts
shown assume that such termination was effective as of December 31, 2013, and are estimates of the allocated amounts 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 such executive’s separation of service.
S. Craig George
Cash Severance
Equity
Restricted Stock/Units
Performance Shares/Units
Total
Other Benefits
Health & Welfare
Tax Gross-Ups
Total
Total
Charles R. Olmstead
Cash Severance
Equity
Restricted Stock/Units
Performance Shares/Units
Total
Other Benefits
Health & Welfare
Tax Gross-Ups
Total
Total
$
$
$
Termination Upon
Death, Disability
or Retirement
Termination
Without Cause
640,000
—
—
1,142,500
1,782,500
—
15,574
—
15,574
1,798,074
$
$
240,000
—
—
1,142,500
1,382,500
—
15,574
—
15,574
1,398,074
Qualifying
Termination
Following
Change in Control
480,000
—
—
1,142,500
1,622,500
—
15,574
—
15,574
1,638,074
$
$
Termination Upon
Death, Disability
or Retirement
Termination
Without Cause
Qualifying
Termination
Following
Change in Control
640,000
$
240,000
$
480,000
—
—
1,142,500
1,782,500
—
15,574
—
15,574
—
—
1,142,500
1,382,500
—
15,574
—
15,574
—
—
1,142,500
1,622,500
—
15,574
—
15,574
$
1,798,074
$
1,398,074
$
1,638,074
93
Jeffrey R. Olmstead
Cash Severance
Equity
Restricted Stock/Units
Performance Shares/Units
Total
Other Benefits
Health & Welfare
Tax Gross-Ups
Total
Total
Termination Upon
Death, Disability
or Retirement
Termination
Without Cause
$
$
760,000
—
—
1,142,500
1,902,500
—
21,382
—
21,382
1,923,882
$
$
360,000
—
—
1,142,500
1,502,500
—
21,382
—
21,382
1,523,882
Qualifying
Termination
Following
Change in Control
720,000
—
—
1,142,500
1,862,500
—
21,382
—
21,382
1,883,882
$
$
Relation of Compensation Policies and Practices to Risk Management
Our compensation policies and practices are designed to provide rewards for short-term and long-term performance, both
on an individual basis and at the 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 excessive risks to reach performance
thresholds which qualify them for additional compensation. From a risk management perspective, our policy is to conduct our
commercial activities in a manner intended to control and minimize the potential for unwarranted risk taking. We also routinely
monitor and measure the execution and performance of our projects and acquisitions relative to expectations. Additionally, our
compensation arrangements include delaying the rewards and subjecting such rewards to forfeiture for terminations related to
violations of our risk management policies and practices or of our code of conduct.
Compensation Committee Interlocks and Insider Participation
The NASDAQ listing rules do not require a listed limited partnership to establish a compensation committee, and we do
not have a compensation committee. Although the board of directors of our general partner does not currently intend to
establish a compensation committee, it may do so in the future.
Compensation of Directors
We use a combination of cash and unit-based compensation to attract and retain qualified candidates to serve on our
board. In setting director compensation, 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 members of the board.
In 2013, directors who were not officers or employees of us or our affiliates received an annual retainer of $40,000, with
the chairman of the audit committee and chairman of the conflict committee receiving an additional annual fee of $5,000. In
addition, each non-employee director receives $1,000 per committee meeting attended in person or by phone and is reimbursed
for his out of pocket expenses in connection with attending meetings. We indemnify each director for his actions associated
with being a director to the fullest extent permitted under Delaware law.
Each of the independent directors were awarded 2,500 common units in January 2013 except for Mr. Ball who became a
director in April 2013. Mr. Ball's common units were prorated for the remainder of 2013 and he received 1,875 common units
on July 24, 2013. The common units were fully vested at the grant date.
The following table discloses the cash unit awards and other compensation earned, paid or awarded to each of our
directors during the year ended December 31, 2013:
94
Name (1)
Peter Adamson III
Cameron O. Smith
Robert W. Berry
Peter A. Leidel
C. Fred Ball Jr.
Fee Earned or
Paid in Cash
Unit Awards (2)
Total
$
55,000
$
56,025
$
55,000
50,000
45,000
36,000
56,025
56,025
56,025
46,669
111,025
111,025
106,025
101,025
82,669
(1) Messrs. Olmstead, George, Olmstead and Wiggins are not included in this table as they are employees of Mid-Con
(2)
Energy Operating and receive no compensation for their services as directors.
Reflects the fair value of the units granted in January 2013 except for Mr. Ball whose fair value reflects when his
units were granted in July 2013.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of March 5, 2014, the following table sets forth the beneficial ownership of our common units that are owned by:
•
•
•
beneficial owners of more than 5% of our common units;
each executive officer of our general partner; and
all directors, director nominees and executive officers of our general partner as a group.
Name of Beneficial Owner
Yorktown Energy Partners VI, L.P. (1)(2)
Yorktown Energy Partners VII, L.P. (1) (3)
Yorktown Energy Partners VIII, L.P. (1)(4)
Kayne Anderson Capital Advisors, L.P./Richard A. Kayne (6)(7)
Mid-Con Energy III, LLC (8)
Charles R. Olmstead (5)
Jeffrey R. Olmstead (5)
S. Craig George (5)
David A. Culbertson (5)
Nathan P. Pekar (5)
Dr. Michael L. Wiggins (5)
Peter Adamson III (5)
Robert W. Berry (5)
Peter A. Leidel (5)
Cameron O. Smith (5)
C. Fred Ball Jr. (5)
All named executive officers, directors and director nominees as a group
(11 people)
______________________
Common Units
to be Beneficially Owned
Percentage of
Common Units
to be Beneficially Owned
140,436
37,207
2,308,720
3,042,865
1,500,000
671,778
334,829
309,085
77,283
20,834
20,000
17,500
39,692
87,686
32,786
10,725
1,622,198
0.7%
0.2%
11.0%
14.4%
7.1%
3.2%
1.6%
1.5%
0.4%
0.1%
0.1%
0.1%
0.2%
0.4%
0.2%
0.1%
7.7%
(1)
(2)
(3)
Has a principal business address of 410 Park Avenue, 19th Floor, New York, New York 10022.
Yorktown VI Company LP is the sole general partner of Yorktown Energy Partners VI, L.P. Yorktown VI
Associates LLC is the sole general partner of Yorktown VI Company LP. As a result, Yorktown VI Associates LLC
may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the common
units owned by Yorktown Energy Partners VI, L.P. Yorktown VI Company LP and Yorktown VI Associates LLC
disclaim beneficial ownership of the common units owned by Yorktown Energy Partners VI, L.P. in excess of their
pecuniary interests therein.
Yorktown VII Company LP is the sole general partner of Yorktown Energy Partners VII, L.P. Yorktown VII
Associates LLC is the sole general partner of Yorktown VII Company LP. As a result, Yorktown VII Associates
LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the
95
common units owned by Yorktown Energy Partners VII, L.P. Yorktown VII Company LP and Yorktown VII
Associates LLC disclaim beneficial ownership of the common units owned by Yorktown Energy Partners VII, L.P.
in excess of their pecuniary interests therein.
Yorktown VIII Company LP is the sole general partner of Yorktown Energy Partners VIII, L.P. Yorktown VIII
Associates LLC is the sole general partner of Yorktown VIII Company LP. As a result, Yorktown VIII Associates
LLC may be deemed to have the power to vote or direct the vote or to dispose or direct the disposition of the
common units owned by Yorktown Energy Partners VIII, L.P. Yorktown VIII Company LP and Yorktown VIII
Associates LLC disclaim beneficial ownership of the common units owned by Yorktown Energy Partners VIII, L.P.
in excess of their pecuniary interests therein.
c/o Mid-Con Energy GP, LLC, 2501 North Harwood Street, Suite 2410, Dallas, Texas 75201
Has a principal business address of 1800 Avenue of the Stars, 3rd Floor, Los Angeles, CA 90067.
This information has been derived from a Schedule 13G filed with the SEC on February 13, 2014. Based on the
information contained in the filing, Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne have shared
voting power and dispositive power with respect to, and beneficially own, an aggregate of 3,042,865 common
units.
Has a principal business address of 2431 E. 61st Street, Suite 850, Tulsa, OK 74136
(4)
(5)
(6)
(7)
(8)
The following table sets forth the beneficial ownership of equity interests in our general partner.
Name of Beneficial Owner
Charles R. Olmstead(1)
S. Craig George(1)
Jeffrey R. Olmstead(1)
______________________
Member Interest(2)
33.33%
33.33%
33.33%
(1)
c/o Mid-Con Energy GP, LLC, 2501 North Harwood Street, Suite 2410, Dallas, Texas 75201
(2) Messrs. Olmstead, George, and Olmstead, by virtue of their ownership interest in our general partner, may be
deemed to beneficially own the interests in us held by our general partner. Each of Messrs. Olmstead, George and
Olmstead disclaims beneficial ownership of these securities in excess of his pecuniary interest in such securities.
Securities Authorized for Issuance under Equity Compensation Plan
See the table in “Item 11. Executive Compensation—Long-Term Incentive Program”.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
As of December 31, 2013, our general partner has an approximate 1.8% interest in us. The distributions we will make to
our general partner are described under Item 5.
Agreements with Affiliates in Connection with the Transactions
The following agreements were negotiated among affiliated parties and, consequently, are not the result of arm’s length
negotiations. The following is a description of those agreements that have been entered into with the affiliates of our general
partner and with our general partner.
Reimbursement of Expenses
We entered into a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating
provides certain services to us, including management, administrative and operational services to us, which include marketing,
geological and engineering 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. These expenses include, among
other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our
behalf and other expenses allocated by Mid-Con Energy Operating to us. Mid-Con Energy Operating has substantial discretion
to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. Mid-Con Energy Operating
will not be liable to us for its performance of, or failure to perform, services under the services agreement unless its acts or
omissions constitute gross negligence or willful misconduct. For the year ended December 31, 2013, we reimbursed Mid-Con
Energy Operating approximately $3.6 million for direct operating expenses.
96
Other Transactions with Related Persons
Operating Agreements
We, various third parties with an ownership interest in the same property and our affiliate, Mid-Con Energy Operating,
are party to standard oil and gas joint operating agreements, pursuant to which we and those third parties pay Mid-Con Energy
Operating overhead charges associated with operating our properties (commonly referred to as the Council of Petroleum
Accountants Societies, or COPAS, fee). We and those third parties pay Mid-Con Energy Operating for its direct and indirect
expenses that are chargeable to the wells under their respective operating agreements.
Review, Approval or Ratification of Transactions with Related Persons
We 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 our general 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 our general partner on the other. The
resolution of any such conflict or potential conflict will be addressed in accordance with our general partner's organizational
documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our
general partners’ board of directors, or the conflicts committee of our general partner's board of directors. Our Code of Business
Conduct is on our website www.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 of directors 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 by affiliates of our general
partner. In so doing, we expect the board of directors (or the conflicts committee) will consider a number of factors 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 drilling inventory 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 of directors 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, given that the Founders and Yorktown are our largest unitholders, they may
consider the potential positive impact on their underlying investment in us by causing the Mid-Con Affiliates to offer properties
to us at attractive purchase prices. Likewise, the affiliates of our general partner 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 Independence
NASDAQ does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors
on the board of directors of our general partner. For a discussion of the independence of the board of directors of our general
partner, please see “Item 10. Directors, Executive Officers and Corporate Governance.”
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The audit committee of Mid-Con Energy GP, LLC selected Grant Thornton LLP, an independent registered public
accounting firm, to audit our consolidated financial statements for the year ended December 31, 2013 and 2012. The audit
committee’s charter requires the audit committee to approve in advance 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, 2013 were approved by the audit
committee.
Fees paid to Grant Thornton LLP are as follows:
97
Audit fees
Audit-Related
Tax fees
Total
2013
2012
304,438
$
277,769
— $
122,030
426,468
$
$
10,000
115,075
402,844
$
$
$
$
98
PART IV
ITEM 15. EXHIBITS
(a)(1) Exhibits
The exhibits listed below are filed or furnished as part of this report:
Exhibit
Number
Description
3.1
3.2
3.3
3.4
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
Certificate of Limited Partnership of Mid-Con Energy Partners, LP (incorporated by reference to Exhibit 3.1
to Mid-Con Energy Partners, LP’s registration statement on Form S-1 filed with the SEC on August 12,
2011 (File No.333-176265)).
Certificate of Formation of Mid-Con Energy GP, LLC (incorporated by reference to Exhibit 3.4 to Mid-Con
Energy Partners, LP’s registration statement on Form S-1 filed with the SEC on August 12, 2011 (File
No. 333-176265)).
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 on December 23, 2011).
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 on December 23, 2011).
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 Energy Partners, LP’s current report on Form 8-K filed with the SEC
on December 23, 2011).
Credit Agreement, dated as of December 20, 2011, among Mid-Con Energy Properties, LLC, as Borrower,
Royal Bank of Canada, as Administrative Agent and Collateral Agent and the lenders party thereto
(incorporated by reference to Exhibit 10.2 to Mid-Con Energy Partners, LP’s current report on Form 8-K
filed with the SEC on December 23, 2011).
Agreement and Amendment No. 1 to Credit Agreement, dated as of April 23, 2012, among Mid-Con Energy
Properties, LLC, as Borrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent and the
lenders party thereto (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 April 27, 2012).
Agreement and Amendment No. 2 to Credit Agreement, dated as of November 26, 2012, among Mid-Con
Energy Properties, LLC, as Borrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent
and the lenders party thereto (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 28, 2012).
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 by reference 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).
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)).
Form of Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.5 to Mid-Con Energy
Partners, LP’s current report on Form 8-K filed with the SEC on December 23, 2011).
Employment Agreement, dated as of August 1, 2011, by and among Mid-Con Energy Partners, LP, Mid-Con
Energy GP, LLC and Charles R. Olmstead (incorporated by reference to Exhibit 10.6 to Mid-Con Energy
Partners, LP’s current report on Form 8-K filed with the SEC on December 23, 2011).
Employment Agreement, dated as of August 1, 2011, by and among Mid-Con Energy Partners, LP, Mid-Con
Energy GP, LLC and Jeffrey R. Olmstead (incorporated by reference to Exhibit 10.7 to Mid-Con Energy
Partners, LP’s current report on Form 8-K filed with the SEC on December 23, 2011).
Employment Agreement, dated as of August 1, 2011, by and among Mid-Con Energy Partners, LP, Mid-Con
Energy GP, LLC and S. Craig George (incorporated by reference to Exhibit 10.8 to Mid-Con Energy
Partners, LP’s current report on Form 8-K filed with the SEC on December 23, 2011).
99
10.11
10.12
10.13
Purchase and Sale Agreement dated February 28, 2014 by and among Mid-Con Energy III, LLC, Mid-Con
Energy Properties, LLC and Mid-Con Energy Partners, LP (incorporated by reference to Exhibit 2.1 to Mid-
Con Energy, LP’s current report on Form 8-K filed with the SEC on March 5, 2014).
Form of Crude Oil Purchase Agreement between Mid-Con Energy Operating, Inc. and Enterprise Crude Oil
LLC.
Agreement and Amendment No.3 to Credit Agreement, dated as of November 5, 2013, among Mid-Con
Energy Properties, LLC, as Borrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent
and the lenders party thereto (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 6, 2013).
10.14+*
Form of Phantom Unit Award Agreement (for employees of our Affiliate).
21.1
22.1+
23.1+
23.2+
31.1+
31.2+
32.1+
32.2+
99.1+
Subsidiaries of Mid-Con Energy Partners, LP
Amendment No.1 to Employment Agreement, dated as of January 29, 2014, by and among Mid-Con Energy
Partners, LP, Mid-Con Energy GP, LLC and S. Craig George.
Consent of Cawley, Gillespie & Associates, Inc.
Consent of Grant Thornton LLP
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
Section 1350 Certification of Chief Executive Officer
Section 1350 Certification of Chief Financial Officer
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 upon request.
+
++
*
Filed herewith
Furnished herewith
Certain confidential portions of this exhibit were omitted. This exhibit, with the omitted information, has been filed
separately with the U.S. Securities and Exchange Commission pursuant to an Application for Confidential Treatment
under Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
100
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
SIGNATURES
Date: March 5, 2014
Mid-Con Energy Partners, LP
(Registrant)
By: Mid-Con Energy GP, LLC, its general partner
By:
/s/ Jeffrey R. Olmstead
Jeffrey R. Olmstead
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities indicated on March 5, 2014.
Signature
/s/ Charles R. Olmstead
Charles R. Olmstead
/s/ Jeffrey R. Olmstead
Jeffrey R. Olmstead
/s/ David A. Culbertson
David A. Culbertson
/s/ Peter A. Leidel
Peter A. Leidel
/s/ Cameron O. Smith
Cameron O. Smith
/s/ Robert W. Berry
Robert W. Berry
/s/ Peter Adamson III
Peter Adamson III
/s/ C. Fred Ball Jr.
C. Fred Ball Jr.
/s/ Michael L. Wiggins
Michael L. Wiggins
/s/ S. Craig George
S. Craig George
Title
Chief Executive Officer and Director
(Principal Executive Officer)
President, Chief Financial Officer and Director
(Principal Financial Officer)
Date
March 5, 2014
March 5, 2014
Vice President and Chief Accounting Officer
March 5, 2014
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
March 5, 2014
March 5, 2014
March 5, 2014
March 5, 2014
March 5, 2014
March 5, 2014
Executive Chairman of the Board
March 5, 2014
101
Leadership
Unitholder Information
Executive Management
S. Craig George
Executive Chairman of the Board
Charles R. Olmstead
Chief Executive Officer
Jeffrey R. Olmstead
President, Chief Financial Officer
Michael L. Wiggins
Executive Vice President, Chief Engineer
Public Headquarters
2501 N. Harwood Street
Suite 2410
Dallas, TX 75201
(972) 479-5980
Tulsa Operations
2431 E. 61st Street
Suite 850
Tulsa, OK 74136
(918) 743-7575
David A. Culbertson
Chief Accounting Officer
Exchange: Ticker Symbol
NASDAQ: MCEP
Nathan P. Pekar
VP of Business Development, General Counsel
Website
www.midconenergypartners.com
Board of Directors
Peter Adamson III (i)(a)(c)
C. Fred Ball, Jr. (i)(a)
Robert W. Berry (i)(a)(c)
S. Craig George
Peter A. Leidel
Charles R. Olmstead
Jeffrey R. Olmstead
Cameron O. Smith (i)(a)(c)
Michael L. Wiggins
(i) Independent Director; (a) Member of the Audit
Committee; (c) Member of the Conflicts
Committee
Investor Relations Contacts
Jeffrey R. Olmstead
Krista K. McKinney
Transfer Agent
Wells Fargo Shareowner Services
1110 Centre Pointe Curve
Suite 101
MAC N9173-010
Mendota Heights, MN 55120
Independent Accounting Firm
Grant Thornton LLP
2431 E. 61st Street
Suite 500
Tulsa, OK 74136
Independent Reserve Engineers
Cawley, Gillespie & Associates, Inc.
306 West Seventh Street
Suite 302
Fort Worth, TX 76102
(972) 479-5980
2501 N. Harwood Street
Suite 2410
Dallas, TX 75201
www.midconenergypartners.com