2016 Annual Report
RETURN DRIVEN, MID-CONTINENT
FOCUSED COMPANY POSITIONED FOR
FUTURE GROWTH.
TO MY FELLOW SHAREHOLDERS
This past year was a transformative one for Midstates
Petroleum. Despite suffering the lowest commodity price levels
in a decade, our talented management, technical and financial
teams accomplished some very meaningful results.
We spent much of 2016 restructuring our balance sheet to give
us the financial flexibility to continue to develop our portfolio of
Mississippian Lime properties. We were able to create value with
these assets even in a low commodity price environment like last
year. By the end of 2016, we had completed our restructuring
and eliminated approximately $2 billion in debt and $185 million
of annualized interest expense. Through this process, Midstates
emerged a stronger, leaner operator with a solid financial base
we can use to exploit our tremendous assets.
During most of 2016, we operated a one-rig drilling program
to mitigate production declines and to preserve and grow key
acreage. Our operational and land teams significantly expanded
our acreage position through low cost farm-in arrangements
and meaningfully added to our inventory of drilling locations.
During 2016, we grew our Mississippian Lime acreage in Woods
and Alfalfa Counties, OK by 51% to 104,000 net acres, added 121
technical proved undeveloped (PUD) locations, and reported
year-end proved reserves of 177 million barrels of oil equivalent.
We also focused on operational excellence and capital efficiency
to maximize margins and cash flow through a combination of
cost reductions and cycle time improvements. Over the past two
years, we reduced our average drilling, completion and facility
costs for new wells by 35% to approximately $2.6 million per
well. We also achieved a 42% improvement in drilling cycle times,
averaging 13.3 days per well in 2016.
Throughout 2016, our operations and regulatory teams
proactively and efficiently addressed seismicity concerns
regarding salt-water disposal (SWD) into the Arbuckle
formation. By year-end 2016, 42% of our SWD injection was
into formations other than the Arbuckle and we are currently
in compliance with Oklahoma Corporation Commission (OCC)
injection requirements. We plan to permit all future SWD
wells for disposal into formations other than the Arbuckle and
we currently have five undrilled SWD wells with all permits
approved and two SWD wells with pending permits before the
OCC. We believe that our looped salt-water disposal system
provides us the operational flexibility to cost effectively meet
any future OCC Arbuckle injection limits without material
curtailments of hydrocarbon production.
Looking ahead to 2017, we will maintain our emphasis on
maximizing margins, being financially disciplined and delivering
on our operational guidance. Earlier this year, we announced our
2017 capital program of $90 to $100 million with a near-term
one-rig drilling program, focused solely in the Mississippian
Lime and funded with internally generated cash flow and
available cash on hand. Our high quality Mississippian Lime
assets generate strong rates of return in the current commodity
price environment and our short-term strategy looks to further
develop these assets, grow reserves, and enhance our current
production and cash flow. With a strong balance sheet and
outstanding operations, we have the financial and operational
flexibility to execute on our strategy.
On behalf of the Board of Directors and senior management, I
would like to thank our employees for their dedication and focus,
which has allowed us to build a strong foundation for the future.
I would also like to thank you, our fellow shareholders, for your
continued support. We are excited about the opportunities within
the Company’s asset base and are committed to growing those
assets to create significant value for our shareholders in 2017
and beyond.
Sincerely,
Frederic F. Brace
President and Chief Executive Officer
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(cid:1) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
(cid:2) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
OR
For the transition period from
to
.
Commission File Number: 001-35512
MIDSTATES PETROLEUM COMPANY, INC.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
321 South Boston Avenue, Suite 1000
Tulsa, Oklahoma
(Address of principal executive offices)
45-3691816
(I.R.S. Employer
Identification No.)
74103
(Zip Code)
Securities registered pursuant to Section 12(b) of the Act:
Registrant’s telephone number, including area code: (918) 974-8550
Common stock, $0.01 par value
NYSE MKT
(Title of each class)
(Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:2) No (cid:1)
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 (cid:2) No (cid:1)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days. Yes (cid:1) No (cid:2)
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 (cid:1) No (cid:2)
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 (cid:1)
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 (cid:2)
Accelerated filer (cid:2)
Non-accelerated filer (cid:2)
(Do not check if a
smaller reporting company)
Smaller reporting company (cid:1)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:2) No (cid:1)
The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $1.2 million
based upon the closing price of such stock on June 30, 2016, the last business day of the registrant’s most recently completed second fiscal
quarter, of $0.15 per share.
The number of shares outstanding of our stock at March 27, 2017 is shown below:
Class
Number of shares outstanding
Common stock, $0.01 par value
24,994,867
DOCUMENTS INCORPORATED BY REFERENCE
None.
MIDSTATES PETROLEUM COMPANY, INC.
TABLE OF CONTENTS
Item
PART I
1.
BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1A. RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1B. UNRESOLVED STAFF COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.
LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.
MINE SAFETY DISCLOSURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.
PART II
5.
6.
7.
MARKET FOR THE 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . .
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . . . .
8.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
9.
AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9A. CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9B. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE . . . . . . .
EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
12.
MANAGEMENT AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . .
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . . . . . . . . . . . . . . .
PRINCIPAL ACCOUNTING FEES AND SERVICES . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
EXHIBITS, FINANCIAL STATEMENT SCHEDULES . . . . . . . . . . . . . . . . . . . . . . . . . .
FORM 10-K SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13.
14.
15.
16.
Page
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47
47
48
50
55
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83
83
83
84
85
85
85
85
85
86
88
2
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements that are subject to a
number of risks and uncertainties, many of which are beyond our control. All statements other than
statements of historical fact included in this annual report are forward-looking statements, including,
without limitation, statements regarding our strategy, future operations, financial position, estimated
revenues and income/loss, projected costs, prospects, plans and objectives of management. When used
in this annual report, the words ‘‘could,’’ ‘‘believe,’’ ‘‘anticipate,’’ ‘‘intend,’’ ‘‘estimate,’’ ‘‘expect,’’ ‘‘may,’’
‘‘continue,’’ ‘‘predict,’’ ‘‘potential,’’ ‘‘project’’ and similar expressions are intended to identify forward-
looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements may include statements about our:
(cid:127) business strategy, including our business strategy post-emergence from our Chapter 11 cases (the
‘‘Chapter 11 Cases’’);
(cid:127) estimated future net reserves and present value thereof;
(cid:127) technology;
(cid:127) financial condition, revenues, cash flows and expenses;
(cid:127) levels of indebtedness, liquidity, borrowing capacity and compliance with debt covenants;
(cid:127) financial strategy, budget, projections and operating results;
(cid:127) oil and natural gas realized prices;
(cid:127) timing and amount of future production of oil and natural gas;
(cid:127) availability of drilling and production equipment;
(cid:127) the amount, nature and timing of capital expenditures, including future development costs;
(cid:127) availability of oilfield labor;
(cid:127) availability of third party natural gas gathering and processing capacity;
(cid:127) availability and terms of capital;
(cid:127) drilling of wells, including our identified drilling locations;
(cid:127) successful results from our identified drilling locations;
(cid:127) marketing of oil and natural gas;
(cid:127) the integration and benefits of asset and property acquisitions or the effects of asset and
property acquisitions or dispositions on our cash position and levels of indebtedness;
(cid:127) infrastructure for salt water disposal and electricity;
(cid:127) current and future ability to dispose of salt water;
(cid:127) sources of electricity utilized in operations and the related infrastructures;
(cid:127) costs of developing our properties and conducting other operations;
(cid:127) general economic conditions;
(cid:127) effectiveness of our risk management activities;
(cid:127) environmental liabilities;
(cid:127) counterparty credit risk;
3
(cid:127) the outcome of pending and future litigation;
(cid:127) governmental regulation and taxation of the oil and natural gas industry;
(cid:127) developments in oil and natural gas producing countries;
(cid:127) new capital structure and the adoption of fresh start accounting, including the risk that
assumptions and factors used in estimating enterprise value vary significantly from the current
estimates in connection with the application of fresh start accounting;
(cid:127) uncertainty regarding our future operating results; and
(cid:127) plans, objectives, expectations and intentions contained in this annual report that are not
historical.
All forward-looking statements speak only as of the date of this annual report. You should not
place undue reliance on these forward-looking statements. These forward-looking statements are
subject to a number of risks, uncertainties and assumptions. Although we believe that our plans,
intentions and expectations reflected in or suggested by the forward-looking statements we make in this
annual report are reasonable, we can give no assurance that these plans, intentions or expectations will
be achieved or occur, and actual results could differ materially and adversely from those anticipated or
implied in the forward-looking statements. We disclose important factors that could cause our actual
results to differ materially from our expectations under ‘‘Risk Factors’’ and elsewhere in this annual
report.
These factors include:
(cid:127) variations in the market demand for, and prices of, oil, natural gas liquids and natural gas;
(cid:127) uncertainties about our estimated quantities of oil and natural gas reserves;
(cid:127) the adequacy of our capital resources and liquidity including, but not limited to, access to
additional borrowing capacity under our reserves based revolving credit facility (the ‘‘Exit
Facility’’);
(cid:127) access to capital and general economic and business conditions;
(cid:127) uncertainties about our ability to replace reserves and economically develop our current reserves;
(cid:127) risks in connection with acquisitions;
(cid:127) risks related to the concentration of our operations onshore in Oklahoma and Texas;
(cid:127) drilling results;
(cid:127) the potential adoption of new governmental regulations, including future regulations regarding
the disposal of salt water; and
(cid:127) our ability to satisfy future cash obligations and environmental costs.
These cautionary statements qualify all forward-looking statements attributable to us or persons
acting on our behalf.
Reserve engineering is a process of estimating underground accumulations of oil and natural gas
that cannot be measured in an exact way. The accuracy of any reserves estimate depends on the quality
of available data (including geoscience and engineering data), the interpretation of such data and price
and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and
production activities may justify revisions of estimates that were made previously. If significant, such
revisions would change the schedule of any future production and development drilling. Accordingly,
reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.
4
GLOSSARY OF OIL AND NATURAL GAS TERMS
Bbl: One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil,
condensate or natural gas liquids.
Boe: Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel
of oil.
Boe/day: Barrels of oil equivalent per day.
Completion: The process of treating a drilled well followed by the installation of permanent
equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.
Dry hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production do not exceed production expenses and taxes.
Exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously
found to be productive of natural gas or oil in another reservoir.
MMBoe: One million barrels of oil equivalent.
MMBtu: One million British thermal units.
Net acres: The percentage of total acres an owner has out of a particular number of acres, or a
specified tract.
NYMEX: The New York Mercantile Exchange.
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 drill or operate
expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic
or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the project within a
reasonable time. The area of the reservoir considered as proved includes (i) the area identified by
drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that
can, with reasonable certainty, be judged to be continuous with it and to contain economically
producible oil or natural gas on the basis of available geoscience and engineering data. In the absence
of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known
hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and
reliable technology establishes a lower contact with reasonable certainty. Where direct observation from
well penetrations has defined a highest known oil elevation and the potential exists for an associated
gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if
geoscience, engineering, or performance data and reliable technology establish the higher contact with
reasonable certainty. Reserves which can be produced economically through application of improved
recovery techniques (including, but not limited to, fluid injection) are included in the proved
classification when (i) successful testing by a pilot project in an area of the reservoir with properties no
more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir
or an analogous reservoir, or other evidence using reliable technology establishes the reasonable
certainty of the engineering analysis on which the project or program was based; and (ii) the project
has been approved for development by all necessary parties and entities, including governmental
entities. Existing economic conditions include prices and costs at which economic producibility from a
reservoir is to be determined. The price is the average price during the 12-month period prior to the
5
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.
Reasonable certainty: A high degree of confidence.
Recompletion: The process of re-entering an existing wellbore that is either producing or not
producing and completing new reservoirs in an attempt to establish, re-establishing, or increase existing
production.
Reserves: Estimated remaining quantities of oil and natural gas and related substances anticipated
to be economically producible as of a given date by application of development projects to known
accumulations.
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 reservoirs.
Spud or Spudding: The commencement of drilling operations of a new well.
Wellbore: The hole drilled by the bit that is equipped for oil or gas production on a completed
well. Also called well or borehole.
Working interest: The right granted to the lessee of a property to explore for and to produce and
own oil, natural gas, or other minerals. The working interest owners bear the exploration, development,
and operating costs on a cash, penalty, or carried basis.
6
ITEM 1. BUSINESS
General
PART I
Midstates Petroleum Company, Inc. is an independent exploration and production company
focused on the application of modern drilling and completion techniques in oil and liquids-rich basins
in the onshore United States. Our operations are concentrated in Oklahoma and Texas, with our
corporate headquarters located in Tulsa, Oklahoma. Midstates Petroleum Company, Inc. was
incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding
company for Midstates Petroleum Company LLC (‘‘Midstates Sub’’ or ‘‘Debtor Affiliate’’). In this
Annual Report, references to ‘‘Company,’’ ‘‘we,’’ ‘‘us,’’ ‘‘our,’’ and ‘‘Midstates’’ when used in the
present tense, prospectively or for historical periods, refer to Midstates Petroleum Company, Inc. and
its wholly owned subsidiary.
Our common stock was listed on the New York Stock Exchange (the ‘‘NYSE’’) on April 25, 2012
through February 3, 2016 under the symbol ‘‘MPO’’. On February 3, 2016, our stock was delisted by the
NYSE and began trading on the OTC Pink market under the symbol ‘‘MPOY’’. On April 30, 2016, we
filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code.
On October 21, 2016, in connection with our emergence from Chapter 11, our existing common shares
traded under the symbol MPOY were cancelled and on October 24, 2016, our new common shares
issued in connection with our successful reorganization and emergence from Chapter 11 were listed and
began trading on the NYSE MKT under the symbol ‘‘MPO’’. We currently lease office space in Tulsa,
Oklahoma at 321 South Boston Avenue, Suite 1000, where our principal offices are located. The lease
for our Tulsa office expires in 2026. We also lease one field office in Dacoma, Oklahoma and one in
Perryton, Texas. As of December 31, 2016, we had 124 employees.
We are required to file annual, quarterly and current reports, proxy statements and other
information with the Securities and Exchange Commission (‘‘SEC’’). You may read and copy any
documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E.,
Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room
by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from
commercial document retrieval services and at the SEC’s website at http://www.sec.gov. Our reports,
proxy statements and other information filed with the SEC can also be inspected and copied at the
New York Stock Exchange, 20 Broad Street, New York, New York 10005.
We also make available on our website (http://www.midstatespetroleum.com) all of the documents
that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file
such material with the SEC. Our Code of Business Conduct and Ethics, Corporate Governance
Guidelines, Financial Code of Ethics, and the charters of our audit committee, compensation
committee and nominating and governance committee are also available on our website and in print
free of charge to any stockholder who requests them. Requests should be sent by mail to 321 South
Boston Avenue, Suite 1000; Tulsa, Oklahoma 74103, attention Vice President—General Counsel.
Information contained on our website is not incorporated by reference into this Annual Report on
Form 10-K. We intend to disclose on our website any amendments or waivers to our Code of Ethics
that are required to be disclosed pursuant to Item 5.05 of Form 8-K.
Chapter 11 Plan of Reorganization
On April 30, 2016 (the ‘‘Petition Date’’), we filed voluntary petitions for reorganization under
Chapter 11 of the United States Bankruptcy Code (the ‘‘Bankruptcy Code’’) in the United States
Bankruptcy Court for the Southern District of Texas (the ‘‘Bankruptcy Court’’). Our Chapter 11 cases
(the ‘‘Chapter 11 Cases’’) were jointly administered under the case styled In re Midstates Petroleum
7
Company, Inc., et al., Case No. 16-32237. On September 28, 2016, the Bankruptcy Court entered the
Findings of Fact, Conclusions of Law, and Order Confirming Debtors’ First Amended Joint Chapter 11
Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate (the ‘‘Confirmation
Order’’), which approved and confirmed the First Amended Joint Chapter 11 Plan of Reorganization of
Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on the same date (the ‘‘Plan’’). On
October 21, 2016 (the ‘‘Effective Date’’), we satisfied the conditions to effectiveness set forth in the
Confirmation Order and in the Plan, the Plan became effective in accordance with its terms and we
emerged from the Chapter 11 Cases. Pursuant to the confirmed Plan, the significant transactions that
occurred upon the Effective Date were as follows:
(cid:127) Substantial Deleveraging of the Balance Sheet: The permanent pay-down of $81.3 million of our
revolving credit facility (‘‘RBL’’), with a $170.0 million Exit Facility established upon the
Effective Date, (ii) the pay-down of $60.0 million of our Second Lien Notes in cash, and (iii) the
conversion into equity of all of our remaining debt junior to the RBL;
(cid:127) Credit Facility Claims: Holders of allowed claims arising under the RBL (the ‘‘Credit Facility
Claims’’) received their pro rata share of approximately $81.3 million in cash and the RBL was
superseded, pursuant to the Plan, by the Exit Facility, as further described below;
(cid:127) Second Lien Notes Claims: Holders of allowed claims arising under the Second Lien Notes (the
‘‘Second Lien Notes Claims’’) received their pro rata share of (i) 96.25% of the reorganized
equity in the form of common stock and (ii) a cash payment of $60.0 million;
(cid:127) Third Lien Notes Claims: Holders of allowed claims arising under the Third Lien Notes (the
‘‘Third Lien Notes Claims’’), pursuant to a settlement with holders of Second Lien Notes Claims
on terms more fully set forth in the Plan (the ‘‘Second/Third Lien Plan Settlement’’), received
their pro rata share of 2.5% of the reorganized equity in the form of common stock and
warrants to acquire 4,411,765 shares of common stock at a strike price of $24.00 per common
share with an expiration date 42 months after the Effective Date;
(cid:127) Unsecured Claims: Holders (the ‘‘Unsecured Noteholders’’) of allowed claims arising under the
Debtors’ 10.75% Senior Unsecured Notes due 2020 (the ‘‘2020 Notes Claims’’), the holders of
allowed claims arising under the 9.25% Senior Unsecured Notes due 2021 (the ‘‘2021 Notes
Claims’’ and together with the 2020 Notes Claims, the ‘‘Unsecured Notes Claims’’), and the
Holders of other general unsecured claims received their pro rata share of 1.25% of reorganized
equity in the form of common stock and warrants to acquire 2,213,789 shares of common stock
(the ‘‘Unencumbered Assets Equity Distribution’’) at a strike price of $46.00 per common share
with an expiration date 42 months after the Effective Date;
(cid:127) Existing Equity: All existing equity interests prior to the Effective Date were extinguished, and
existing equity holders did not receive any consideration in respect of their equity interests;
(cid:127) New Equity: On the Effective Date, we issued 24,687,500 shares of common stock of the
reorganized equity. On November 9, 2016, we issued an additional 294,967 shares of common
stock of the reorganized equity pursuant to the Plan. We will issue 17,533 additional common
shares, with respect to general unsecured claims, pursuant to the Plan in a future distribution.
The total authorized reorganized capital stock consists of 250,000,000 shares of common stock
and 50,000,000 shares of preferred stock;
(cid:127) Exit Facility: Our RBL, which was redetermined with a borrowing base of $170.0 million in April
2016, was superseded, pursuant to the Plan, by the Exit Facility. The Exit Facility has an initial
borrowing base of $170.0 million with no borrowing base redeterminations to occur until April
2018 (provided certain conditions are met) and semiannual borrowing base redeterminations
each year on April 1 and October 1 thereafter. Until April 2018, unless the borrowing base is
redetermined earlier, the amount available to be drawn under the Exit Facility is reduced by
8
$40.0 million, and thereafter, we must maintain liquidity (as defined in the Exit Facility) equal to
at least 20.0% of the effective borrowing base. In connection therewith, on the Effective Date,
we made an additional payment of $40.0 million to lenders under our Exit Facility; and
(cid:127) Long-Term Incentive Plan: A management equity incentive plan (the ‘‘2016 LTIP’’) was
established under which 10.0% of the reorganized equity (on a fully-diluted/fully-distributed
basis) was reserved for grants to be made from time to time to the directors, officers, and other
members of our management.
As a result of our restructuring, we estimate cash paid for interest will decrease from
approximately $173.7 million per year to approximately $7.0 million per year, a cash interest savings of
approximately $166.7 million per year.
The following table provides adjustments that reflect the consummation of transactions
contemplated by the Plan, as of the Effective Date (excluding the Exit Facility):
As of
October 21, 2016
Predecessor
Reorganization October 21, 2016
Adjustments
Successor
As of
(in thousands)
Unsecured Notes:
2020 Senior Notes . . . . . . . . . . . . .
2021 Senior Notes . . . . . . . . . . . . .
Total Unsecured Notes . . . . . . . .
Secured Notes:
Second Lien Term Loan . . . . . . . . .
Third Lien Term Loan . . . . . . . . . .
Total Secured Notes . . . . . . . . . .
Total Debt (excluding Exit Facility) . .
$
$
$
$
$
293,625
347,652
641,277
625,000
529,653
$
$
$
(293,625) $
(347,652)
(641,277) $
(625,000) $
(529,653)
1,154,653
$ (1,154,653) $
1,795,930
$ (1,795,930) $
—
—
—
—
—
—
—
Upon our emergence on the Effective Date, we adopted fresh start accounting as required by
United States generally accepted accounting principles (‘‘US GAAP’’). We qualified for fresh start
accounting because (i) the holders of existing voting shares of the pre-emergence debtor-in-possession
received less than 50% of the voting shares of the post-emergence successor entity and (ii) the
reorganization value of our assets immediately prior to confirmation was less than the post-petition
liabilities and allowed claims. We applied fresh start accounting as of October 21, 2016. Adopting fresh
start accounting results in a new reporting entity for financial reporting purposes with no beginning
retained earnings or deficit. The cancellation of all existing shares outstanding on the Effective Date
and issuance of new shares in the reorganized Company caused a related change of control under
US GAAP. As a result of the application of fresh start accounting, as well as the effects of the
implementation of the Plan, our consolidated financial statements on or after October 21, 2016, are not
comparable with our consolidated financial statements prior to that date. References to ‘‘Successor
Period’’ relate to the financial position and results of operations for the period October 21, 2016
through December 31, 2016 and references to ‘‘Predecessor Period’’ refer to the financial position and
results of operations of the Company from January 1, 2016 through October 20, 2016.
Business Strategy
Our goal is to grow our reserves, production and cash flows to generate an attractive rate of return
on invested capital. To achieve these objectives, we strive to:
(cid:127) Operate in a safe and environmentally responsible manner;
9
(cid:127) Capitalize on our extensive technical and operating experience in our core areas of operation to
strategically grow our production, increase our acreage position and enhance returns;
(cid:127) Build contiguous acreage positions that drive operating and infrastructure efficiencies;
(cid:127) Be the operator of our assets, whenever possible; and
(cid:127) Be the low cost driller and producer in the areas where we operate.
As a result of our recent restructuring, our significantly deleveraged balance sheet and improved
liquidity position provides us with additional resources to develop our multi-year drilling inventory and
expand our core acreage positions. Our focus will continue to be on controlling development and
production costs and general and administrative expenses. For 2017, we intend to opportunistically
increase our development activity while maintaining capital discipline and protecting our operating cash
flows, including through the use of derivatives to protect our commodity price realizations.
With respect to the Mississippian Lime, we believe our team’s early experience operating in this
trend gives us a competitive advantage with respect to geological understanding, drilling and completion
techniques and infrastructure development. We plan to leverage our advantages to cost effectively
develop our Mississippian position and further expand our acreage through direct leasing, farm in
arrangements and acreage swaps. During 2016, we earned approximately 24,248 net (45,440 gross)
prospective acres through various farm-in agreements and plan to continue to utilize such agreements
in the future. With respect to the Anadarko Basin, we believe our substantial acreage position largely
held by production, the stacked pay characteristics of the trend and its long production history provide
significant optionality with continued improvement in commodity prices and geologic understanding.
For 2017, we plan to allocate substantially all of our drilling and completions capital budget to
development activities in the Mississippian Lime area based on the stronger economic returns expected
from these assets in the current commodity price environment.
Summary of Oil and Gas Properties and Operations
Mississippian Lime
Our Mississippian Lime assets are located in Oklahoma and target the Mississippian Lime and
Hunton formations. At December 31, 2016, our acreage consisted of approximately 103,093 net
(142,773 gross) prospective acres in the Mississippian Lime trend in Woods and Alfalfa Counties of
Oklahoma, which we currently intend to develop using horizontal wells, and approximately 12,894 net
(19,888 gross) acres in Lincoln County, Oklahoma, which produces from, and is prospective in, the
Hunton formation.
Our properties in this area represented 96% of our total proved reserves as of December 31, 2016.
As of December 31, 2016, we held an average working interest and average net revenue interest of
82% and 66%, respectively, in this area.
For the Successor Period and Predecessor Period, our average daily production from our
Mississippian Lime assets was as follows:
Successor
Predecessor
Period October 21, 2016
through December 31, 2016
Period January 1, 2016
through October 20, 2016
Oil (Bbls) . . . . . . . . . . . . . . . . . . . .
Natural gas liquids (Bbls) . . . . . . . . .
Natural gas (Mcf) . . . . . . . . . . . . . .
Net Boe/day . . . . . . . . . . . . . . . . . . .
6,048
4,843
58,816
20,694
8,156
5,326
68,107
24,833
10
At December 31, 2016, we had one operated drilling rig in operation in the Mississippian Lime.
For 2017, subject to the terms of our Exit Facility, we anticipate investing between $90.0 million and
$100.0 million in the area while drilling between 24 and 26 gross operated wells.
Anadarko Basin
Our Anadarko Basin assets are located in Western Oklahoma and the Texas panhandle and target,
or are prospective in, the Cleveland, Marmaton, Cottage Grove, Osage, Meramac and Tonkawa
formations. At December 31, 2016, our acreage consisted of approximately 80,298 net (96,753 gross)
acres in Texas and 24,627 net (43,671 gross) acres in western Oklahoma.
Our properties in this area represented 4% of our total proved reserves as of December 31, 2016.
As of December 31, 2016, we held an average working interest and average net revenue interest of
64% and 51%, respectively, in this area.
For the Successor Period and Predecessor Period, our average daily production from the Anadarko
Basin area was as follows:
Successor
Predecessor
Period October 21, 2016
through December 31, 2016
Period January 1, 2016
through October 20, 2016
Oil (Bbls) . . . . . . . . . . . . . . . . . . . .
Natural gas liquids (Bbls) . . . . . . . . .
Natural gas (Mcf) . . . . . . . . . . . . . .
Net Boe/day . . . . . . . . . . . . . . . . . . .
1,508
1,118
9,903
4,277
1,927
1,247
10,856
4,983
As of December 31, 2016, we did not operate any drilling rigs in this area and we do not expect to
operate any drilling rigs in 2017. As a result, leasehold rights on acreage not held by production may
expire during 2017, which could reduce our future drilling opportunities in this area. During 2016, we
entered into a farm out agreement covering our acreage in Dewey County, Oklahoma which may be
prospective for the NW Stack extension. To the extent commercially feasible, we will continue to pursue
farm out arrangements with other operators to cost effectively preserve a portion of our leasehold
rights with optionality to participate in any future development. During 2017, we will continue our
efforts to reduce well maintenance and operating costs and production downtime. These efforts alone
have not been and will not be sufficient to arrest the natural decline in production that occurs as we
deplete our developed reserves.
Other
On April 21, 2015, we closed on the sale of certain of our oil and gas properties in Beauregard
and Calcasieu Parishes, Louisiana (the ‘‘Dequincy Divestiture’’), for approximately $44.0 million, before
customary post-closing adjustments. We have no proved reserves in the Gulf Coast (or Louisiana) as of
December 31, 2016 or 2015.
11
Reserves Information
Estimated Proved Reserves
The following table sets forth our estimated net proved reserves by product and type as of
December 31, 2016 using SEC pricing:
Oil (MBls)
Natural
Gas
(MMcf)
NGLs
(MBbls)
Total
(MBoe)
PV-10(1)
(in millions)
Mississippian Lime:
Proved developed producing . . . . . . . . . . . . . .
Proved developed non-producing . . . . . . . . . . .
Proved undeveloped . . . . . . . . . . . . . . . . . . . .
15,358
1,540
41,692
162,997
20,335
270,905
12,673
1,597
20,523
55,197
6,526
107,366
$ 306,623
20,553
216,493
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
58,590
454,237
34,793
169,089
$ 543,669
Anadarko Basin:
Proved developed producing . . . . . . . . . . . . . .
Proved developed non-producing . . . . . . . . . . .
Proved undeveloped . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,800
—
—
2,800
18,122
—
—
18,122
2,079
—
—
2,079
7,899
—
—
$
34,486
—
—
7,899
$
34,486
Total Proved . . . . . . . . . . . . . . . . . . . . . . . . . . .
61,390
472,359
36,872
176,988
$ 578,155
(1) We refer to PV-10 as the present value of estimated future net cash flows of estimated proved
reserves as calculated in the respective reserves report using a discount rate of 10%. This amount
includes projected revenues, estimated production costs, estimated future development costs and
estimated cash flows related to future asset retirement obligations (‘‘ARO’’). PV-10 is a financial
measure not defined under US GAAP. Accordingly, the following table reconciles total PV-10 to
the standardized measure of discounted future net cash flows, which is the most directly
comparable US GAAP financial measure. We believe the presentation of PV-10 provides useful
information because it is widely used by investors in evaluating oil and natural gas companies
without regard to specific income tax characteristics of such entities. PV-10 is not a measure of
financial or operating performance under US GAAP, nor is it intended to represent the current
market value of our estimated proved reserves. PV-10 should not be considered in isolation or as a
substitute for the standardized measure of discounted future net cash flows as defined under
US GAAP.
The following table provides a reconciliation of PV-10 to the standardized measure of discounted
cash flows (in thousands):
PV-10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Present value of future income tax, discounted at 10% . . . . . . . . . . . . .
$ 578,155
(48,205)
Standardized measure of discounted future net cash flows . . . . . . . . . .
$ 529,950
As of
December 31,
2016
12
Proved Undeveloped Reserves
The following table summarizes the changes in our estimated proved undeveloped reserves during
the Successor Period and Predecessor Period (in MBoe):
Proved undeveloped reserves, December 31, 2015 . . . . . . . . . . . . . . . . . . .
Purchases of reserves in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales of reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of previous estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conversion to proved developed reserves . . . . . . . . . . . . . . . . . . . . . . .
Proved undeveloped reserves, October 20, 2016 . . . . . . . . . . . . . . . . . . . . .
Purchases of reserves in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales of reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of previous estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conversion to proved developed reserves . . . . . . . . . . . . . . . . . . . . . . .
4,430
—
—
—
—
(4,430)
—
—
—
62,997
48,019
(3,650)
Proved undeveloped reserves, December 31, 2016 . . . . . . . . . . . . . . . . . . .
107,366
Due to uncertainty during the Predecessor Period regarding our ability to finance the development
of our proved undeveloped reserves over a five year period, our proved undeveloped reserves were
limited to only those locations that were undergoing drilling activity. Upon our emergence on the
Effective Date, we undertook a process to review our five year development schedule in light of
improved commodity pricing and the significant improvement in the Company’s liquidity and
outstanding long-term debt. In developing the Company’s updated five year development schedule, the
Company considered the forward pricing curve, the returns expected of our drilling program and cash
available during this time period, which would include cash on hand, cash generated by operations and
cash from borrowings. Based upon these factors, the Company developed an updated five year
development plan and booked proved undeveloped reserves based upon this expected development
plan. Proved undeveloped reserves that were removed from the proved category in prior years but
subsequently reinstated after this review were classified as a revision in the above table. Proved
undeveloped reserves that were not included in any proved category in prior years but included in our
updated five-year development schedule were classified as an extension in the above tables. At
December 31, 2016, 21,103 net MBoe of proved undeveloped reserves, comprising $34.1 million of
PV-10 value were excluded from our five year development plan.
Independent Petroleum Engineers
For our Mississippian Lime and Anadarko Basin assets, our estimated reserves and related future
net revenues at December 31, 2016, 2015 and 2014 are based on reports prepared by our independent
third-party reserves engineering firm Cawley, Gillespie & Associates, Inc. (‘‘CGA’’), in accordance with
generally accepted petroleum engineering and evaluation principles and definitions and guidelines in
effect during such period as established by the SEC.
The reserve estimates shown herein for the periods indicated above have been independently
evaluated by CGA, a worldwide leader of petroleum property analysis for industry and financial
organizations and government agencies. CGA was founded in 1961 and performs consulting petroleum
engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA,
the technical person primarily responsible for preparing the estimates set forth in the reserves report
incorporated herein was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum
engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas
(License No. 71055) and has over 29 years of practical experience in petroleum engineering, with over
13
27 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M
University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or
exceeds the education, training, and experience requirements set forth in the Standards Pertaining to
the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of
Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering
and geoscience evaluations as well as applying SEC and other industry reserve definitions and
guidelines.
Our estimated reserves and related future net revenues for our Gulf Coast (or Louisiana) assets at
December 31, 2014 were based on reports prepared by an independent third-party reserves engineering
firm, Netherland, Sewell & Associates, Inc. (‘‘NSAI’’), in accordance with generally accepted petroleum
engineering and evaluation principles and definitions and guidelines in effect during such period
established by the SEC.
The reserve estimates shown herein for the periods indicated above were independently evaluated
by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations
and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering
services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the
technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves
report incorporated herein are Mr. Robert C. Barg and Mr. Philip R. Hodgson. Mr. Barg, a Licensed
Professional Engineer in the State of Texas (No. 71658), has been practicing consulting petroleum
engineering at NSAI since 1989 and has over 6 years of prior industry experience. He graduated from
Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering.
Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1314), has been
practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry
experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in
Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both
technical principals meet or exceed the education, training, and experience requirements set forth in
the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry
standard practices to engineering and geoscience evaluations as well as applying SEC and other
industry reserves definitions and guidelines.
Technology Used to Establish Proved Reserves
Under Rule 4-10(a)(22) of Regulation S-X, as promulgated by the SEC, proved reserves are those
quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically producible from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government
regulations. The term ‘‘reasonable certainty’’ implies a high degree of confidence that the quantities of
oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be
established using techniques that have been proved 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.
In order to establish reasonable certainty with respect to our estimated proved reserves, CGA and
NSAI employed technologies that have been demonstrated to yield results with consistency and
repeatability. The technologies and economic data used in the estimation of our proved reserves
include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and
available downhole and production data, seismic data and well test data.
14
Internal Controls Over Reserves Estimation Process
We maintain an internal staff of petroleum engineers, land and geoscience professionals who work
closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data
furnished to CGA and NSAI in their reserves estimation process. The primary inputs to the reserves
estimation process are comprised of technical information, financial data, ownership interests and
production data. All field and reservoir technical information, which is updated annually, is assessed for
validity when the reservoir engineers hold technical meetings with geoscientists, operations and land
personnel to discuss field performance and to validate future development plans. Current revenue and
expense information is obtained from our accounting records, which are subject to their own set of
internal controls over financial reporting. All current financial data such as commodity prices, lease
operating expenses, production taxes and field commodity price differentials are updated in the reserves
database and then analyzed to ensure that they have been entered accurately and that all updates are
complete. Our current ownership in mineral interests and well production data are incorporated into
the reserves database as well and verified to ensure their accuracy and completeness. Throughout each
fiscal year, our technical team meets with representatives of our independent reserve engineers to
review properties and discuss methods and assumptions used in preparation of the proved reserve
estimates. While we have no formal committee specifically designated to review reserves reporting and
the reserves estimation process, the reserves report is reviewed by our senior management with
representatives of our independent reserve engineers and internal technical staff.
At December 31, 2016, Jeromy Garcia, our General Manager—Mississippian Lime and Anadarko
Basin Assets and Reserves, was primarily responsible for overseeing the preparation of our reserve
estimates and reported directly to our Chief Executive Officer. Mr. Garcia has more than 16 years of
experience in the oil and gas industry. Mr. Garcia spent the first portion of his career working for El
Paso Production Company—primarily working assets in the Gulf of Mexico. While at El Paso,
Mr. Garcia served in multiple roles including reservoir and operational engineering. Mr. Garcia has
also worked for small independents such as Whittier Energy and J&S Oil & Gas where he served as a
reservoir engineer and Manager of Engineering. Mr. Garcia graduated from the University of
Oklahoma in 2000 with a B.S degree in Petroleum Engineering and obtained his MBA from the
University of Houston in 2009.
Production, Revenues and Price History
Oil, natural gas liquids (‘‘NGLs’’) and natural gas are commodities. The price that we receive for
the oil, NGLs and natural gas we produce is largely a function of market supply and demand. The
price of oil substantially declined in the fourth quarter of 2014 and remained depressed throughout
2015 due to a variety of macro-economic factors. While oil, natural gas and NGL prices increased
throughout 2016, they remain substantially below the price levels realized during the majority of 2014.
A decline in oil or natural gas prices from their current levels could have a material adverse effect on
our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that
may be economically produced and our ability to access capital markets. For additional information on
these and other risks, see information set forth in ‘‘Risk Factors’’.
The following table sets forth information regarding our oil, NGLs and natural gas production,
revenues and realized prices and production costs for the Successor Period, the Predecessor Period and
15
the years ended December 31, 2015 and 2014. For additional details, see information set forth in
‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations.’’
Successor
Period October 21,
2016 through
December 31, 2016
Predecessor
Period January 1, Year Ended
Year Ended
December 31, December 31,
2016 through
October 20, 2016
2015
2014
544
429
4,948
1,798
24,971
46.96
46.96
19.55
19.55
2.76
2.76
$
$
$
$
$
$
8.52
1.78
0.72
0.12
7.22
$
$
$
$
$
— $
$
— $
— $
— $
2.71
2,964
1,932
23,215
8,765
29,816
4,794
2,473
28,403
12,001
32,880
5,144
2,417
25,013
11,730
32,137
37.99 $
37.99 $
45.40 $
74.74 $
90.71
87.40
14.22 $
15.46 $
36.31
14.22 $
15.46 $
36.40
2.08 $
2.35 $
2.08 $
3.30 $
6.02 $
1.64 $
0.59 $
0.16 $
7.11 $
26.48 $
2.55 $
— $
0.87 $
— $
6.79 $
1.30 $
0.72 $
0.13 $
16.55 $
135.47 $
3.22 $
0.03 $
3.01 $
0.18 $
3.97
3.91
6.79
1.14
2.07
0.15
23.01
7.37
4.15
0.35
—
0.44
Operating Data:
Net production volumes:
Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbls) . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf) . . . . . . . . . . . . . . . . .
Total oil equivalents (MBoe) . . . . . . . . . . .
Average daily production (Boe/d) . . . . . . . .
Average Sales Prices:
Oil, without realized derivatives (per Bbl) . . $
Oil, with realized derivatives (per Bbl) . . . . $
Natural gas liquids, without realized
derivatives (per Bbl) . . . . . . . . . . . . . . . $
Natural gas liquids, with realized derivatives
(per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . $
Natural gas, without realized derivatives
(per Mcf) . . . . . . . . . . . . . . . . . . . . . . . $
Natural gas, with realized derivatives
(per Mcf) . . . . . . . . . . . . . . . . . . . . . . . $
Costs and Expenses (per Boe of production):
Lease operating and workover . . . . . . . . . . $
Gathering and transportation . . . . . . . . . . . $
Severance and other taxes . . . . . . . . . . . . . $
Asset retirement accretion . . . . . . . . . . . . . $
Depreciation, depletion and amortization . . $
Impairment of oil and gas properties . . . . . $
General and administrative . . . . . . . . . . . . $
Acquisition and transaction costs . . . . . . . . $
Debt restructuring costs and advisory fees . $
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
16
The following table sets forth information regarding oil, NGLs and natural gas daily production for
each of the fields that represented more than 15% of our estimated total proved reserves for the
Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014:
Mississippian(1)
Daily production volumes:
Oil (Bbls) . . . . . . . . . . . . . . . . . . . . . . . .
NGLs (Bbls) . . . . . . . . . . . . . . . . . . . . . .
Natural gas (Mcf) . . . . . . . . . . . . . . . . . .
Total oil equivalents (Net Boe/day) . . . .
Anadarko
Daily production volumes:
Oil (Bbls) . . . . . . . . . . . . . . . . . . . . . . . .
NGLs (Bbls) . . . . . . . . . . . . . . . . . . . . . .
Natural gas (Mcf) . . . . . . . . . . . . . . . . . .
Total oil equivalents (Net Boe/day) . . . .
Successor
Predecessor
Period
October 21, 2016
through
Period
January 1, 2016
through
December 31, 2016 October 20, 2016
Year Ended
December 31,
2015
Year Ended
December 31,
2014
6,035
4,464
56,740
19,956
1,508
1,118
9,903
4,277
8,147
4,968
65,737
24,071
1,927
1,247
10,856
4,983
10,187
4,900
62,514
25,506
2,680
1,388
12,921
6,222
8,401
4,093
50,164
20,855
4,014
1,766
14,930
8,268
(1) These volumes represent only Mississippian Lime production and do not include Hunton
production volumes.
Productive Wells
The following table presents our total gross and net productive wells as of December 31, 2016:
Oil
Natural Gas
Total
Gross
Net
Gross
Net Gross
Net
Total productive wells . . . . . . . . . . . . . . . . .
753
527
93
67
846
594
Productive wells consist of producing wells and wells capable of producing. Gross wells are the
total number of productive wells in which we have working interests, and net wells are the sum of our
fractional working interests owned in gross wells. Each gross well completed in more than one
producing zone is counted as a single well.
Acreage
The following table sets forth certain information regarding the developed and undeveloped
acreage in which we have a controlling interest as of December 31, 2016 for each of our operating
areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this
summary:
Developed Acres
Undeveloped Acres
Total Acres
Gross
Net
Gross
Net
Gross
Net
Mississippian Lime . . . . . . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . .
80,048
57,440
—
58,070
36,926
—
82,613
82,984
4,920
57,917
67,999
4,431
162,661
140,424
4,920
115,987
104,925
4,431
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
137,488
94,996
170,517
130,347
308,005
225,343
17
Undeveloped Acreage Expirations
The following table sets forth the number of gross and net undeveloped acres as of December 31,
2016 that will expire over the next three years by operating area unless operations are commenced
upon or production is established upon the acreage (or upon lands spaced or pooled therewith) or we
make additional lease rental payments prior to the expiration dates:
Expiring 2017
Expiring 2018
Expiring 2019
Gross
Net
Gross
Net
Gross
Net
Mississippian Lime . . . . . . . . . . . . . . . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
27,248
18,500
4,860
14,540
10,124
4,406
7,119
1,480
60
3,799
899
25
768
1,439
402
72
— —
Total Undeveloped Acreage Expirations . . . . . . . . . . . .
50,608
29,070
8,659
4,723
1,841
840
Approximately 15.6% of our net acreage, including acreage under option, was acquired in 2016,
with the majority of such leases under three year primary term leases. In addition, our typical lease
terms along with unit regulatory rules generally provide us flexibility to continue lease ownership
through either establishing production or actively drilling prospects. Because of our reduced activity
levels in the Anadarko Basin and divestitures in Louisiana, we may allow leasehold rights on acreage
not held by production to expire in these areas, which could reduce our future drilling opportunities.
Additionally, to the extent we cannot commence drilling operations upon or establish production from
certain leases in the Mississippian Lime asset, certain of the leases within that asset area will expire,
unless extended or renewed.
Drilling Activity
The following table summarizes our drilling activity for the Successor Period, the Predecessor
Period and the years ended December 31, 2015 and 2014. Gross wells reflect the sum of all wells in
which we own an interest. Net wells reflect the sum of our working interests in gross wells:
Successor
Period
October 21,
2016 through
December 31,
2016
Period
January 1,
2016 through
October 20,
2016
Predecessor
Year Ended
December 31,
2015
Year Ended
December 31,
2014
Gross
Net Gross
Net Gross
Net Gross
Net
Development wells:
Productive . . . . . . . . . . . . . . . . . . . . . . . . . .
Dry holes . . . . . . . . . . . . . . . . . . . . . . . . . . .
3
3
— —
40
38
— —
84
74
— —
119
97
— —
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
3
3
40
38
84
74
119
97
Exploratory wells:
Productive . . . . . . . . . . . . . . . . . . . . . . . . . .
Dry holes . . . . . . . . . . . . . . . . . . . . . . . . . . .
— —
— —
— —
— —
— —
3 —
1
1
— —
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
— —
— —
3 —
1
Total wells . . . . . . . . . . . . . . . . . . . . . . . .
3
3
40
38
87
74
120
1
98
As of December 31, 2016, there were four gross (and four net) development wells awaiting
completion; one development well was being drilled and no exploratory wells were being drilled.
18
As of December 31, 2016, we had one drilling rig in operation. Our recent drilling activity has
primarily focused on development, delineation and appraisal of our primary operating areas in our
Mississippian Lime asset.
Marketing and Major Purchasers
We sell our oil, NGLs and natural gas to third-party purchasers. We are not dependent upon, or
contractually limited to, any one purchaser or small group of purchasers other than in our Mississippian
Lime asset, where the majority of our natural gas production is dedicated to one purchaser for the
economic life of the relevant assets. For the Successor Period, two purchasers accounted for 40% and
29%, respectively, of the Company’s revenue. For the Predecessor Period, two purchasers accounted for
46% and 29%, respectively, of the Company’s revenue. For the year ended December 31, 2015, two
purchasers accounted for 43% and 25%, respectively, of the Company’s revenue. For the year ended
December 31, 2014, four purchasers accounted for 28%, 18%, 15% and 12% respectively, of the
Company’s revenue. Due to the nature of oil, NGLs and natural gas markets, and because we sell our
oil production to purchasers that transport by truck rather than by pipelines, we do not believe the loss
of a single purchaser or a few purchasers would materially adversely affect our ability to sell such
production.
We are party to a gas purchase, gathering and processing contract in our Mississippian Lime asset,
which includes certain minimum NGL volume commitments. To the extent we do not deliver natural
gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered
NGLs, we would be required to reimburse the counterparty an amount equal to the sum of the
monthly shortfall, if any, multiplied by a fee of roughly $0.08 to $0.125 per gallon (subject to annual
escalation). We have historically, and continue to currently, deliver at least the minimum volumes
required under these contractual provisions.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct a preliminary review of the
title to our properties on which we do not have proved reserves. Prior to the commencement of drilling
operations on those properties, we conduct a more thorough title examination and undertake any title
curative that is deemed necessary to address any significant title discrepancies. To the extent title
opinions or other investigations reflect any such significant defects affecting those properties, we are
responsible for curing any such defects at our expense to the extent that any such defect impacts our
ownership interest. Likewise, we may choose to notify other owners whose title is subject to a title
defect so that they may undertake the necessary efforts to attempt to cure the applicable title defect at
their own expense. Our oil and natural gas properties are generally subject to customary royalty
interests or other burdens, and a majority of our properties are subject to liens to secure borrowings
under our Exit Facility as well as liens for current taxes and other burdens, none of which we believe
materially interfere with our ability to operate or develop such properties.
Seasonality
Weather conditions often affect the demand for, and the associated prices of, crude oil, natural gas
and NGLs. Further, weather conditions could delay our drilling and production activities, which impacts
our ability to achieve our overall business objectives. Generally, demand for oil and natural gas
decreases during the spring and fall months and increases during the summer and winter months.
However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation.
19
Competition
The oil and natural gas industry is a highly competitive environment for acquiring properties,
attracting and retaining trained personnel and obtaining the equipment necessary to develop and
produce reserves. We compete with numerous entities, including major domestic and foreign oil
companies, other independent oil and natural gas companies and individual producers and operators.
Many of these competitors are large, well established companies and have financial and other resources
substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to
discover reserves in the future will depend upon our ability to evaluate and select suitable properties
and successfully consummate transactions in this highly competitive environment.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. In
particular, oil and natural gas production and related operations are, or have been, subject to price
controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or
operate properties for oil and natural gas production have statutory provisions regulating the
exploration for and production of oil and natural gas, including provisions related to permits for the
drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon which wells are drilled,
sourcing and disposal of water used in the drilling and completion process and produced during
operations and the abandonment of wells. Our operations are also subject to various conservation laws
and regulations. These include regulation of the size of drilling and spacing units or proration units, the
number of wells which may be drilled in any given area, and the unitization or pooling of oil and
natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and
impose certain requirements regarding the ratability or fair apportionment of production from fields
and/or individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The
regulatory burden on our industry increases the cost of doing business and affects profitability.
Although we believe we are in substantial compliance with all applicable laws and regulations, and that
continued substantial compliance with existing requirements will not have a material adverse effect on
our financial position, cash flows or results of operations, such laws and regulations are frequently
amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or
past non-compliance with environmental laws or regulations may be discovered. Therefore, we are
unable to predict the future costs or impact of compliance. Additional proposals and proceedings that
affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal
Energy Regulatory Commission (‘‘FERC’’) and the courts. We cannot predict when or whether any
such proposals may become effective.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce has been
regulated by the FERC under the Natural Gas Act of 1938 (‘‘NGA’’), the Natural Gas Policy Act of
1978 (‘‘NGPA’’) and regulations issued under those statutes.
FERC regulates interstate natural gas transportation rates, and terms and conditions of service,
which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales
of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more
accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The natural gas
industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that
the less stringent regulatory approach that FERC has historically maintained will continue. However,
we do not believe that any action taken will affect us in a way that materially differs from the way it
affects other natural gas producers.
20
The price at which we sell natural gas is not currently subject to federal rate regulation and, for
the most part, is not subject to state regulation. However, with regard to our physical sales of these
energy commodities, we are required to observe anti-market manipulation laws and related regulations
enforced by the FERC and/or the Commodity Futures Trading Commission (‘‘CFTC’’) and the Federal
Trade Commission (‘‘FTC’’).
Gathering services, which occur upstream of FERC jurisdictional transmission services, are
regulated by the states onshore and in state waters. Although the FERC has set forth a general test for
determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional
transmission function, the FERC’s determinations as to the classification of facilities is done on a case
by case basis. State regulation of natural gas gathering facilities generally includes various safety,
environmental and, in some circumstances, nondiscriminatory take requirements.
Regulation of Production
The production of oil and natural gas is subject to regulation under a wide range of local, state
and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations
require permits for drilling operations, drilling bonds and reports concerning operations. All of the
states in which we own and operate properties have regulations governing conservation matters,
including provisions for the unitization or pooling of oil and natural gas properties, the establishment
of maximum allowable rates of production from oil and natural gas wells, the regulation of well
spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount
of oil and natural gas that we can produce from our wells and to limit the number of wells or the
locations at which we can drill, although we can apply for exceptions to such regulations or to have
reductions in well spacing. Moreover, each state generally imposes a production or severance tax with
respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
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.
Environmental and Occupational Health and Safety Regulation
Our oil and natural gas exploration, development and production operations are subject to
stringent and complex federal, regional, state and local laws and regulations governing occupational
safety and health, the emission or discharge of materials into the environment and environmental and
natural resource protection. Numerous governmental entities, including the U.S. Environmental
Protection Agency (‘‘EPA’’), analogous state agencies, and, in certain instances, citizens’ groups, have
the power to enforce compliance with these laws and regulations and the permits issued under them,
often requiring difficult and costly actions. These laws and regulations may, among other things
(i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the
types, quantities and concentration of various substances that can be released into the environment or
injected into formations in connection with oil and natural gas drilling and production activities;
(iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other
protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing
operations, such as requirements to close waste pits and plug abandoned wells; (v) impose specific
safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for
pollution resulting from drilling and production operations. 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 injunctions prohibiting some or all of our
operations. These laws and regulations may also restrict the rate of oil and natural gas production
below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas
industry increases the cost of doing business in the industry and consequently affects profitability.
21
Any changes in federal or state environmental laws and regulations or re-interpretation of
applicable enforcement policies that result in more stringent or costly well construction, drilling, water
management or completion activities, waste handling, storage, transport, or disposal requirements, or
remediation requirements or that limit or otherwise restrict the emission of certain listed pollutants or
organic compounds from wells or surface equipment could have a material adverse effect on our
operations and financial position. We may be unable to pass on such increased compliance costs.
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 current requirements would not have a material adverse effect on our financial
condition or results of operations, there is no assurance that we will be able to remain in compliance in
the future with existing or any new laws and regulations or that future compliance with such laws and
regulations will not have a material adverse effect on our business and operating results.
The following is a summary of the more significant existing and proposed environmental and
occupational 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 Wastes
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 the legality of the original conduct on certain classes of persons who are considered
to be responsible for the release of a ‘‘hazardous substance’’ into the environment. These classes of
persons include current and prior owners or operators of the site where the release occurred and
entities that disposed of or arranged for the disposal of the hazardous substances at a site where a
release has occurred. Under CERCLA, these ‘‘responsible parties’’ may be subject to strict, joint and
several liability for the costs of removing and 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 the public health or the environment and to seek to recover from the responsible parties 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 release of hazardous substances or
other pollutants into the environment. Despite the ‘‘petroleum exclusion’’ of Section 101(14) of
CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle
hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our
ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part
of the costs required to clean up sites at which these hazardous substances have been released into the
environment.
Certain of our operations or activities may also be subject to the requirements of the Resource
Conservation and Recovery Act, as amended (‘‘RCRA’’), and comparable state statutes. RCRA imposes
strict requirements on the generation, storage, treatment, transportation and disposal of hazardous and
nonhazardous wastes. Under the authority of the EPA, most states administer some or all of the
provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although
RCRA currently exempts certain drilling fluids, produced waters, and other wastes associated with
exploration, development and production of oil and natural gas from regulation as hazardous wastes,
we can provide no assurance that this exemption will be preserved in the future. From time to time the
EPA and analogous state agencies have considered repealing or modifying this exemption, and citizens’
groups have also petitioned the agency to consider its repeal. Most recently, in August 2015, nonprofit
22
environmental groups filed a notice of intent to sue the EPA regarding its failure to review the RCRA
E&P waste exemption. Repeal or modification of this exemption or similar exemptions under state law
could have a significant impact on our operating costs as well as the oil and natural gas industry in
general. The impact of future revisions to environmental laws and regulations cannot be predicted. In
any event, at present, these excluded wastes are subject to regulation as RCRA nonhazardous wastes.
In addition, we generate petroleum hydrocarbon wastes and ordinary industrial wastes in the course of
our operations that may become regulated as RCRA hazardous wastes if such wastes have hazardous
characteristics.
We currently own or lease, and have in the past owned or leased, properties that have been used
for numerous years to explore and produce oil and natural gas. Although we have utilized operating
and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and
wastes may have been disposed of or released on or under the properties owned or leased by us or on
or under other locations where these petroleum hydrocarbons and wastes have been taken for recycling
or disposal. In addition, certain of these properties have been operated by third parties whose
treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. 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.
Air Emissions
The Clean Air Act, as amended (‘‘CAA’’), 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 of certain pollutants. The need to obtain
permits has the potential to delay the development of oil and natural gas projects. Over the next
several years, we may be required to incur certain capital expenditures for air pollution control
equipment or other air emissions related issues. For example, the EPA published a final rule on
October 1, 2015 that reduces the National Ambient Air Quality Standard for ozone to between 65 and
70 ppb for both the 8-hour primary and secondary standards. In addition, in May 2016, the EPA
finalized rules regarding criteria for aggregating multiple small surface sites into a single source for
air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause
small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent
air permitting requirements. In May 2016, the EPA also issued final rules that require the reduction of
volatile organic compound and methane emissions from additional new, modified or reconstructed oil
and gas emissions sources. Since the methane and aggregation rules were published in the Federal
Register after May 31, 2016, they are potentially subject to repeal by the new Congress. These new
regulations could, among other things, require installation of new emission controls on some of the
drilling program’s equipment and production facilities, result in longer permitting timelines, and
significantly increase our capital expenditures and drilling program’s operating costs, which could
adversely impact our business. Compliance with any one or more of these requirements could increase
our costs of development and production, which costs could be significant.
Climate Change
Based on the EPA’s determination that emissions of carbon dioxide, methane and other greenhouse
gases (‘‘GHGs’’) present an endangerment to public health and the environment because emissions of
such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other
climatic changes, the agency has adopted regulations under existing provisions of the federal CAA that,
23
among other things, establish pre-construction and operating permit reviews for GHG emissions from
certain large stationary sources that already are potential major sources of certain principal, or criteria,
pollutant emissions. Facilities required to obtain permits for their GHG emissions also will be required
to meet ‘‘best available control technology’’ standards that typically will be established by the states. In
addition, the EPA has adopted regulations requiring the monitoring and annual reporting of GHG
emissions from specified sources in the United States, including, among others, certain oil and natural
gas production facilities, which includes certain of our operations. Most recently, in May 2016, the EPA
finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and
natural gas sector. In November 2016, the Bureau of Land Management (‘‘BLM’’) issued final rules to
reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public
lands. The May 2016 and November 2016 methane rules are potentially subject to repeal by the new
Congress. We cannot predict which areas, if any, the EPA may choose to regulate with respect to GHG
emissions next.
A number of state and regional efforts have emerged that are aimed at tracking and/or reducing
GHG emissions by means of cap and trade programs that typically require major sources of GHG
emissions to acquire and surrender emission allowances in return for emitting those GHGs. On an
international level, the United States is one of almost 200 nations that is party to the Paris Agreement
adopted in December 2015 to reduce global GHG emissions. It is not possible at this time to predict if
or when the United States might impose restrictions on GHG emissions as a result of this agreement.
Although it is not possible at this time to predict how legislation or new regulations that may be
adopted to address GHG emissions would impact our business, such requirements could require us to
obtain permits for our GHG emissions, install costly emission controls, pay fees on the emissions data,
and adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted
that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere
may produce climate changes that have significant physical effects, such as increased frequency and
severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they
could have an adverse effect on our financial condition and results of operations.
Water Discharges and Fluid Injections
The Federal Water Pollution Control Act, as amended (the ‘‘Clean Water Act’’), and analogous
state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters
and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except
in accordance with the terms of a permit issued by the EPA or the analogous state agency. Spill
prevention, control and countermeasure requirements under federal law 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 require individual permits or coverage under general permits for discharges of storm water
runoff from certain types of facilities, including oil and natural gas production facilities. The Clean
Water Act also prohibits the discharge of dredge and fill material in regulated waters, including
wetlands, unless authorized by permit. Federal and state regulatory agencies can impose administrative,
civil and criminal penalties, as well as require remedial or mitigation measures, for noncompliance with
discharge permits or other requirements of the Clean Water Act and analogous state laws and
regulations.
The Oil Pollution Act of 1990, as amended (‘‘OPA’’), amends the Clean Water Act and sets
minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels,
offshore facilities, and onshore facilities, including exploration and production facilities that may affect
waters of the United States. Under OPA, responsible parties, including owners and operators of
onshore facilities, may be held strictly liable for oil cleanup costs and natural resource damages as well
as a variety of public and private damages that may result from oil spills. The OPA also requires
24
owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a
worst-case discharge of oil into waters of the United States.
Fluids resulting from oil and natural gas production, consisting primarily of salt water, are disposed
by injection in belowground disposal wells. These disposal wells are regulated pursuant to the
Underground Injection Control (‘‘UIC’’) program established under the federal Safe Drinking Water
Act and analogous state laws. The UIC program requires permits from the EPA or an analogous state
agency for the construction and operation of disposal wells, establishes minimum standards for disposal
well operations, and may restrict the types and quantities of fluids that may be disposed. While we
believe that our disposal well operations substantially comply with requirements under the applicable
UIC programs, a change in disposal well regulations or the inability to obtain permits for new disposal
wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our
operations or reduce the amount of oil and/or natural gas that we can produce from our wells.
There exists a growing concern that the injection of saltwater into belowground disposal wells
contribute to seismic activity in certain areas, including Oklahoma and Texas, where we operate. For
instance, on April 21, 2015, the Oklahoma Geologic Survey (‘‘OGS’’) issued a document entitled
‘‘Statement of Oklahoma Seismicity,’’ in which the agency states ‘‘the OGS considers it very likely that
the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are
triggered by the injection of produced water in disposal wells.’’ In response to these concerns,
regulators in some states, including Oklahoma and Texas, are pursuing initiatives designed to impose
additional requirements in the permitting and operation of saltwater disposal wells or otherwise to
assess any relationship between seismicity and the use of such wells. For example, the Oklahoma
Corporation Commission (‘‘OCC’’) has adopted rules for operators of saltwater disposal wells in certain
seismically-active areas (‘‘Areas of Interest’’) in the Arbuckle formation, requiring operators to monitor
and record well pressure and discharge volume on a daily basis and further requiring operators of wells
permitted for disposal of 20,000 barrels per day or more of saltwater to conduct mechanical integrity
testing. On March 25, 2015, the Oil and Gas Conservation Division (‘‘OGCD’’) issued a directive,
expanding the Areas of Interest for induced seismicity. Under the new directive, operators of 347
disposal wells located within the expanded Areas of Interest of the Arbuckle formation were given until
April 18, 2015 to demonstrate that their wells were not disposing into or in communication with the
crystalline basement rock underlying the Arbuckle formation. Operators of wells in contact or
communication with the basement rock were required to reduce the depth of, or ‘‘plug back,’’ those
wells or, alternatively, to reduce disposal volume by 50 percent. On July 17, 2015, the OGCD issued
another directive, further expanding the covered area to include an additional 211 disposal wells. Under
this second directive, operators were given until August 14, 2015 to prove that they were not injecting
below the Arbuckle formation or, as necessary, to plug back those wells in contact or communication
with the crystalline basement rock, without the option of reducing disposal volume by 50 percent.
On November 19, 2015, the OGCD issued a directive to stop or reduce disposal volumes in the
Cherokee-Carmen area, including 5 wells we currently operate. In addition, on January 13, 2016, the
OGCD announced a plan in response to recent earthquakes in the Fairview area of Oklahoma. The
plan calls for changes to the operations of oil and gas wastewater disposal wells in the area that dispose
into the Arbuckle formation. Under the plan, a total of 27 Arbuckle disposal wells were required to
reduce disposal volume. The plan affected 7 disposal wells we currently operate that dispose in the
Arbuckle formation. On February 16, 2016, the OGCD requested we curtail our wastewater disposal
volumes at 11 wells by approximately 40%. On March 7, 2016 and August 19, 2016, the OGCD
identified additional wells that were required to reduce disposal volume, including nine that we
operate. The OGCD established caps for additional wells, including 16 that we operate, on
February 24, 2017. While our current plans are for future disposal wells to inject into formations other
than the Arbuckle and we currently operate 8 such non-Arbuckle formation disposal wells, we continue
to utilize wells that dispose into the Arbuckle formation. We have timely met and satisfied all requests
25
of the OCC regarding changes and/or reductions in disposal capacity in our operated disposal wells, all
while maintaining our production base without any negative material impact thereto. We believe we are
currently in compliance with the OGCD’s latest requests regarding Arbuckle injection limits; however a
change in disposal well regulations or injection limits, or the inability to obtain permits for new disposal
wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our
operations and/or reduce the volume of oil and natural gas that we produce from our wells.
In Texas, effective on November 17, 2014, the Texas Railroad Commission adopted a new rule
governing permitting or re-permitting of disposal wells that requires, among other things, the
submission of information on seismic events occurring within a specified radius of the disposal well
location, as well as logs, geologic cross sections and structure maps relating to the disposal area in
question. If a permittee or a prospective permittee fails to demonstrate that the saltwater or other
fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be
or determined to be contributing to seismic activity, then the Commission may deny, modify, suspend
or terminate the permit application or existing operating permit for that well.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common industry practice that is used to stimulate
production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing
process involves the injection of water, sand, and/or chemicals under pressure into targeted subsurface
formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic
fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing is typically
regulated by state oil and natural gas commissions, or similar state agencies, but several federal
agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA
published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing
operations; issued final CAA regulations governing performance standards, including standards for the
capture of air emissions released during hydraulic fracturing; issued in June 2016 final effluent limit
guidelines that saltwater from shale resource extraction operations must meet before discharging to
publicly owned wastewater treatment plants; and issued in May 2014 a prepublication of its Advance
Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical
substances and mixtures used in hydraulic fracturing. The air emissions standards issued in May 2016
and the effluent limit guidelines issued in June 2016 are potentially subject to repeal by the new
Congress. Also, the BLM published a final rule containing disclosure requirements and other mandates
for hydraulic fracturing on federal and Indian lands in March of 2015. However, the U.S. District Court
of Wyoming struck down this rule in June 2016; the ruling is currently on appeal before the U.S. Tenth
Circuit Court of Appeals.
In addition, Congress has from time to time considered the adoption of legislation to provide for
federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the
hydraulic fracturing process. Some states, including Louisiana, Texas and Oklahoma, where we operate,
have adopted, and other states are considering adopting legal requirements that could impose more
stringent permitting, public disclosure or well construction requirements on hydraulic fracturing
activities. Some states have elected to prohibit hydraulic fracturing altogether, but not the states in
which we own and operate oil and gas wells. Local government also may seek to adopt ordinances
within their jurisdictions regulating the time, place and manner of drilling activities in general or
hydraulic fracturing activities in particular. We believe that we follow applicable standard industry
practices and legal requirements for groundwater protection in our hydraulic fracturing activities.
Nevertheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic
fracturing process 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, and perhaps even be precluded from drilling wells.
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We do not have insurance policies in effect that are intended to provide coverage for losses solely
related to hydraulic fracturing operations; however, we believe our general liability and excess liability
insurance policies would cover third party claims related to hydraulic fracturing operations conducted
by third parties and associated legal expenses in accordance with, and subject to, the terms and
coverage limits of such policies.
Endangered Species
The Endangered Species Act restricts activities that may affect endangered and threatened species
or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty
Act. Oil and gas activities in our operating areas can be adversely affected by seasonal or permanent
restrictions on drilling activities designed to protect various species and their habitat. Seasonal
restrictions could limit our ability to operate in protected areas and can intensify competition for
drilling rigs, oilfield equipment, services, supplies and qualified personnel, which could lead to periodic
shortages when drilling is allowed. These constraints and the resulting shortages or high costs could
delay our operations and materially increase our operating and capital costs. Permanent restrictions
imposed to protect endangered species could prohibit drilling in certain areas or require the
implementation of expensive mitigation measures. The U.S. Fish and Wildlife Service in February 2016
finalized a rule altering how it identifies critical habitat for endangered and threatened species. The
designation of critical habitat areas could materially restrict use of or access to federal, state and
private lands. In addition, as a result of a settlement approved by the U.S. District Court for the
District of Columbia in September 2011, the U.S. Fish & Wildlife Service is required to make a
determination on the listing of numerous species as endangered or threatened under the Endangered
Species Act by 2017. 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 and 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.
Occupational Safety and Health Act, as amended (‘‘OSHA’’)
We are subject to the requirements of 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 comparable state statutes and any
implementing 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.
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ITEM 1A. RISK FACTORS
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere
in this Annual Report on Form 10-K, in our other public filings, press releases and discussions with our
management actually occurs, our business, financial condition or results of operations could suffer. The risks
described below are the known material risk factors facing us. Additional risks not presently known to us or
which we currently consider immaterial also may adversely affect us or our operations.
Risks Related to the Oil and Gas Industry and Our Business
The recent declines in oil and, to a lesser extent, NGL and natural gas prices have adversely affected our
business, financial condition and results of operations and our ability to meet our future capital expenditure
obligations and financial commitments.
The price we receive for our oil and, to a lesser extent, NGLs and natural gas, heavily influences
our revenue, profitability, access to capital and future rate of growth. Oil, NGLs and natural gas are
commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor
changes in supply and demand. Historically, the markets for these commodities have been volatile, and
are likely to continue to be volatile in the future, especially given current economic and geopolitical
conditions. During the period from January 1, 2014 through January 31, 2017, the WTI spot price for
oil declined from a high of $107.95 per Bbl on June 20, 2014 to $26.19 per Bbl on February 11, 2016,
and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on
February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. These markets will likely continue
to be volatile in the future.
The prices we receive for our production and the levels of our production depend on numerous
factors beyond our control. These factors include, but are not limited to, the following:
(cid:127) worldwide and regional economic conditions impacting the global supply and demand for oil,
NGLs and natural gas;
(cid:127) the actions of the Organization of Petroleum Exporting Countries;
(cid:127) the price and quantity of imports of foreign oil, NGLs and natural gas;
(cid:127) political conditions in or affecting other oil, NGL and natural gas-producing countries;
(cid:127) the level of global oil and natural gas exploration and production;
(cid:127) the level of global oil and natural gas inventories;
(cid:127) localized supply and demand fundamentals and transportation availability;
(cid:127) weather conditions and natural disasters;
(cid:127) foreign, domestic and local governmental regulations and taxes;
(cid:127) speculation as to the future price of oil, NGLs and natural gas and the speculative trading of oil,
NGLs and natural gas futures contracts;
(cid:127) price and availability of competitors’ supplies of oil, NGLs and natural gas;
(cid:127) technological advances affecting energy consumption; and
(cid:127) the price and availability of alternative fuels.
The majority of our oil production and a portion of our natural gas production is currently sold to
purchasers under short-term (less than 12-month) contracts at market based prices. The speed and
severity of the decline in oil prices during 2015 and the continued lower prices throughout 2016
adversely affected our cash flows, borrowing ability and the present value of our reserves. Lower oil,
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NGL and natural gas prices may also reduce the amount of oil, NGLs and natural gas that we can
produce economically. Any sustained periods of low prices for oil, NGL and natural gas prices could
render uneconomic a significant portion of our identified drilling locations. This may result in our
having to make significant downward adjustments to our estimated proved reserves. As a result, a low
commodity price environment and price volatility may materially and adversely affect our future
business, financial condition, results of operations, liquidity or ability to finance planned capital
expenditures.
We recently emerged from bankruptcy, which could adversely affect our business and relationships.
It is possible that our having filed for bankruptcy protection and our recent emergence from the
Chapter 11 Cases could adversely affect our business and relationships with our customers, vendors,
royalty or working interest owners, contractors, employees or suppliers. Due to these uncertainties,
many risks exist, including the following:
(cid:127) key suppliers or vendors could terminate their relationship with us or require additional financial
assurances or enhanced performance from us;
(cid:127) the ability to renew existing contracts may be adversely affected;
(cid:127) the ability to attract, motivate and/or retain key executives and employees may be adversely
affected;
(cid:127) employees may be distracted from performance of their duties or more easily attracted to other
employment opportunities; and
(cid:127) landowners may not be willing to lease acreage to us.
The occurrence of one or more of these events could have a material and adverse effect on our
operations, financial condition and reputation. We cannot assure you that having been subject to
bankruptcy protection will not adversely affect our operations in the future.
Our Exit Facility contains certain covenants that may inhibit our ability to make certain investments, incur
additional indebtedness and engage in certain other transactions, which could adversely affect our ability to
meet our future goals.
The Exit Facility limits our ability, among other things, to:
(cid:127) incur additional indebtedness;
(cid:127) incur liens;
(cid:127) enter into sale and lease back transactions;
(cid:127) make certain investments;
(cid:127) make certain capital expenditures;
(cid:127) consolidate, merge, sell, or otherwise dispose of all or substantially all of our assets;
(cid:127) pay dividends or make other distributions or repurchase or redeem our stock;
(cid:127) enter into transactions with our affiliates;
(cid:127) engage or enter into any new lines of business;
(cid:127) enter into certain marketing activities for hydrocarbons;
(cid:127) create additional subsidiaries;
(cid:127) prepay, redeem, or repurchase certain of our indebtedness; and
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(cid:127) amend or modify certain provisions of our (and Midstates Sub’s) organizational documents.
The Exit Facility also requires us to comply with certain financial maintenance covenants as
discussed above. A breach of any of these covenants could result in a default under our Exit Facility. If
a default occurs, the lenders under the Exit Facility may elect to declare all borrowings thereunder
outstanding, together with accrued interest and other fees, to be immediately due and payable. The
lenders under the Exit Facility would also have the right in these circumstances to terminate any
commitments they have to provide further borrowings. If we are unable to repay our indebtedness
when due or declared due, the lenders thereunder will also have the right to proceed against the
collateral pledged to them to secure the indebtedness. If such indebtedness were to be accelerated, our
assets may not be sufficient to repay in full our secured indebtedness.
Upon our emergence from the Chapter 11 Cases, the composition of our board of directors changed
significantly.
Pursuant to the Plan, the composition of the board of directors changed significantly. The new
directors have different backgrounds, experiences and perspectives from those individuals who
previously served on the Board and, thus, may have different views on the issues that will determine
our future. There is no guarantee that the new board of directors will pursue, or will pursue in the
same manner, our current strategic plans. As a result, the future strategy and our plans may differ
materially from those of the past.
The ability to attract and retain key personnel is critical to the success of our business and may be affected by
our emergence from the Chapter 11 Cases.
The success of our business depends on key personnel. The ability to attract and retain these key
personnel may be difficult in light of our emergence from the Chapter 11 Cases, the uncertainties
currently facing the business and changes we may make to the organizational structure to adjust to
changing circumstances. We may need to enter into retention or other arrangements that could be
costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or
their service is otherwise interrupted, we may not be able to replace them in a timely manner and we
could experience significant declines in productivity.
We may be unable to obtain funding in the capital markets on terms we find acceptable, or our borrowings
base may be subject to downward redeterminations in the future.
Historically, we have used our cash flows from operations and borrowings under our RBL to fund
our capital expenditures and have relied on the capital markets and asset monetization transactions to
provide us with additional capital for large or exceptional transactions or to refinance debt obligations.
On the Effective Date, the existing RBL was superseded, and we entered into the Exit Facility with the
lenders under the existing RBL. The Exit Facility has an initial borrowing base of $170.0 million with
no borrowing base redeterminations to occur until April 2018 (provided certain conditions are met) and
semiannual borrowing base redeterminations thereafter. Any reduction in the borrowing base will
reduce our available liquidity, and, if the reduction results in the outstanding amount under the facility
exceeding the borrowing base, we will be required to repay the deficiency within 30 days or in six equal
monthly installments thereafter, at our election. We may not have the financial resources in the future
to make any mandatory deficiency principal prepayments required under our Exit Facility, which could
result in an event of default.
In the future, we may not be able to access adequate funding under our Exit Facility as a result of
(i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base
redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet
their funding obligations. Since the process for determining the borrowing base under our Exit Facility
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involves evaluating the estimated value of some of our oil and natural gas properties using pricing
models determined by the lenders at that time, a decline in those prices used, or further downward
reductions of our reserves, likely will result in a redetermination of our borrowing base and a decrease
in the available borrowing amount at the time of the next scheduled redetermination. In such case, we
would be required to repay any indebtedness in excess of the borrowing base.
Our level of indebtedness may increase and reduce our financial flexibility.
At December 31, 2016, we had $130.0 million outstanding under our Exit Facility, including
$1.9 million in letters of credit. We may incur a significant amount of additional indebtedness in the
future. Should our current level of indebtedness increase significantly, it could affect our operations in
several ways, including the following:
(cid:127) causing a significant portion of our cash flows to be used to service our indebtedness, thereby
reducing the availability of cash flows for working capital, capital expenditures and other general
business activities;
(cid:127) increasing our vulnerability to general adverse economic and industry conditions;
(cid:127) limiting our ability to borrow additional funds, dispose of assets, pay dividends and make certain
investments;
(cid:127) placing us at a competitive disadvantage compared to our competitors that are less leveraged
and, therefore, such competitors may be able to take advantage of opportunities that our
indebtedness would prevent us from pursuing;
(cid:127) causing our debt covenants to affect our flexibility in planning for, and reacting to, changes in
the economy and in our industry;
(cid:127) making it more likely that a reduction in our borrowing base following a redetermination could
require us to repay a portion of our then outstanding bank borrowings; and
(cid:127) impairing our ability to obtain additional financing in the future for working capital, capital
expenditures, acquisitions, general corporate or other purposes.
A high level of indebtedness would increase the risk that we may default on our debt obligations.
Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future
performance. General economic conditions, oil, NGL and natural gas prices and financial, business and
other factors affect our operations and our future performance. Many of these factors are beyond our
control.
We may be unable to maintain compliance with certain financial ratio covenants of our outstanding
indebtedness which could result in an event of default that, if not cured or waived, would have a material
adverse effect on our business, financial condition and results of operations.
Our Exit Facility requires us to maintain certain financial ratios or to reduce our indebtedness if
we are unable to comply with such ratios, including an EBITDA to interest expense coverage ratio
limitation of 3.00:1.00, a ratio limitation of Total Net Indebtedness (as defined in the Exit Facility) to
EBITDA of not more than 2.25:1.00 through April 1, 2018 and not more than 3.00:1.00 thereafter, and
a capital expenditure limitation of $50.0 million for the 6 months ended December 31, 2016,
$81.0 million for the year ended December 31, 2017, $85.0 million for the year ended December 31,
2018 and $78.0 million for the year ended December 31, 2019. Additionally, after April 2018 (unless
the borrowing base is redetermined earlier), we must maintain liquidity (cash plus available
commitments) equal to at least 20.0% of the effective borrowing base.
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As of December 31, 2016, we were in compliance with our financial covenants; however, we cannot
guarantee that we will be able to comply with such terms at all times in the future. Any failure to
comply with the conditions and covenants in our Exit Facility that is not waived by our lenders or
otherwise cured could lead to a termination of our Exit Facility, acceleration of all amounts due under
our Exit Facility, or trigger cross default provisions under other financing arrangements. These
restrictions may limit our ability to obtain future financings to withstand a future downturn in our
business or the economy in general, or to otherwise conduct necessary corporate activities. We may also
be prevented from taking advantage of business opportunities that arise because of the limitations that
the restrictive covenants under our indebtedness impose on us.
Our historical financial information may not be indicative of our future financial performance.
On the effective date of our emergence from the Chapter 11 Cases on October 21, 2016, we
adopted fresh start accounting, as a consequence of which our assets and liabilities were adjusted to
fair values and our accumulated deficit was restated to zero. Accordingly, our financial condition and
results of operations following our emergence from the Chapter 11 Cases may not be comparable to
the financial condition and results of operations reflected in our historical financial statements. Further,
as a result of the implementation of the Plan and the transactions contemplated thereby, our historical
financial information may not be indicative of our future financial performance.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could
adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our
development, drilling and production activities. Our oil and natural gas drilling and production
activities are subject to numerous risks beyond our control, including the risk that drilling will not
result in commercially viable oil or natural gas production. Our decisions to purchase, explore or
develop drilling locations or properties will depend in part on the evaluation of data obtained through
2D and 3D seismic data, geophysical and geological analyses, production data and engineering studies,
the results of which are often inconclusive or subject to varying interpretations. The production and
operating data that is available with respect to our operating areas based on modern drilling and
completion techniques is relatively limited compared to trends where multiple operators have been
active for a significant period of time. As a result, we face more uncertainty in evaluating data than
operators in more developed trends. Our costs of drilling, completing and operating wells are often
uncertain before drilling commences. In addition, the application of new techniques in these trends,
such as high-graded stimulation designs and horizontal completions, may make it more difficult to
accurately estimate these costs. Overruns in budgeted expenditures are common risks that can make a
particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled
drilling projects, including the following:
(cid:127) shortages of, or delays in, obtaining equipment and qualified personnel;
(cid:127) facility or equipment malfunctions;
(cid:127) unexpected operational events;
(cid:127) ability to economically dispose of produced saltwater;
(cid:127) pressure or irregularities in geological formations;
(cid:127) adverse weather conditions;
(cid:127) reductions in oil and natural gas prices;
(cid:127) delays imposed by or resulting from compliance with regulatory requirements;
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(cid:127) proximity to and capacity of transportation facilities;
(cid:127) title problems;
(cid:127) limitations in the market for oil and natural gas; and
(cid:127) cost associated with developing and operating oil and gas properties.
In addition, our hydraulic fracturing operations require significant quantities of water. Regions
where we operate have recently experienced drought conditions. These conditions could persist in the
future, diminishing our access to water for hydraulic fracturing operations. Any diminished access to
water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather
conditions, could curtail our operations or otherwise result in delays in operations or increased costs.
The standardized measure of discounted future net cash flows from our proved reserves will not be the same
as the current market value of our estimated oil and natural gas reserves.
You should not assume that the standardized measure of discounted future net cash flows from
our proved reserves is the current market value of our estimated oil and natural gas reserves. In
accordance with SEC requirements in effect at December 31, 2016, 2015 and 2014, we based the
discounted future net cash flows from our proved reserves on the 12-month unweighted arithmetic
average of the first-day-of-the-month price for the preceding twelve months without giving effect to
derivative transactions. Actual future net cash flows from our oil and natural gas properties will be
affected by factors such as:
(cid:127) actual prices we receive for oil and natural gas;
(cid:127) actual cost of development and production expenditures;
(cid:127) the amount and timing of actual production; and
(cid:127) changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the
development and production of oil and natural gas properties will affect the timing and amount of
actual future net revenues from proved reserves, and thus their actual present value. In addition, the
10% discount factor we use when calculating standardized measure 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. Actual future prices and costs may differ materially from those
used in the present value estimates included in this report which could have a material effect on the
market value of our reserves.
Due to the recent decrease in oil and natural gas prices and if prices decrease in the future, we may be
required to take further write-downs of the carrying values of our oil and natural gas properties.
We use the full cost method of accounting for our oil and gas properties. Accordingly, we
capitalize and amortize all productive and nonproductive costs directly associated with property
acquisition, exploration and development activities. Under the full cost method, the capitalized cost of
oil and gas properties, less accumulated amortization and related deferred income taxes may not exceed
the ‘‘cost center ceiling’’ which is equal to the sum of the present value of estimated future net
revenues from proved reserves, less estimated future expenditures to be incurred in developing and
producing the proved reserves computed using a discount factor of 10%, plus the costs of properties
not subject to amortization, plus the lower of the cost or estimated fair value of unproved properties
included in the costs being amortized, less related income tax effects. If the net capitalized costs exceed
the cost center ceiling, we recognize the excess as an impairment of oil and gas properties. The risk
that we will be required to recognize impairments of our oil and natural gas properties increases during
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periods of low commodity prices. In addition, impairments would occur if we were to experience
sufficient downward adjustments to our estimated proved reserves or the present value of estimated
future net revenues. An impairment recognized in one period may not be reversed in a subsequent
period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent
period. We could incur impairments of oil and natural gas properties in the future, particularly as a
result of future declines in commodity prices.
Oil, NGL and natural gas prices are volatile and a portion of our production is not subject to hedging. As a
result, a portion of our cash flows from operations will be subjected to increased volatility.
Historically, we have entered into hedging transactions of our oil, NGL and natural gas production
to reduce our exposure to fluctuations in the price of oil, NGLs and natural gas. At December 31,
2016, we had no outstanding commodity derivative contracts, although we entered into various
derivatives subsequent to December 31, 2016 for a portion of our expected 2017 and first quarter 2018
production. As such, a portion of our 2017 and 2018 production will be sold at market prices, leaving
us exposed to the fluctuations in the price of oil, NGLs and natural gas and subjecting our cash flows
from operations to increased volatility unless we enter into additional hedging transactions. We will
continually reevaluate and consider whether in the long-term we will hedge any of our future
production.
Any future derivative activities could result in financial losses or could reduce our earnings.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the
prices of oil, NGL and natural gas, we have historically chosen to enter into derivative instruments at
times for a portion of our oil, NGL and natural gas production. We do not designate derivative
instruments as hedges for accounting purposes, and we record all derivative instruments in our balance
sheet at fair value. Changes in the fair value of derivative instruments are recognized in current
earnings. Accordingly, to the extent we enter into derivative instruments in the future, our earnings
may fluctuate significantly as a result of changes in the fair value of any derivative instruments.
Derivative instruments would expose us to the risk of financial loss in some circumstances,
including when:
(cid:127) production is less than the volume covered by the derivative instruments;
(cid:127) the counter-party to the derivative instrument defaults on its contractual obligations; or
(cid:127) there is an increase in the differential between the underlying price in the derivative instrument
and actual prices received for basis differentials.
In addition, any derivative arrangements in the future would likely limit the benefit we would
receive from increases in the prices for oil, NGLs and natural gas.
We have incurred losses from operations during certain periods historically and may continue to do so in the
future.
We incurred a net loss of $1.8 billion for the year ended December 31, 2015. Our development of,
and participation in, an increasing number of drilling locations has required and will continue to
require substantial capital expenditures. The uncertainty and risks described in this report may impede
our ability to economically acquire and develop oil and natural gas reserves. As a result, we may not be
able to achieve or sustain profitability or positive cash flows provided by operating activities in the
future.
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Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any
significant inaccuracies in these assumptions will materially affect the quantities and estimated present value
of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of
available technical data and many assumptions, including assumptions relating to current and future
economic conditions and commodity prices. Any significant inaccuracies in these assumptions could
materially affect the estimated quantities and present value of reserves shown in this report. See
‘‘Summary of Oil and Gas Properties and Operations’’ for information about our estimated oil and
natural gas reserves.
In order to prepare our estimates, we must estimate production rates and the timing of
development expenditures. We must also analyze available geological, geophysical, production and
engineering data. The extent, quality and reliability of this data can vary. The process also requires
economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. Estimates of oil and natural gas reserves are
inherently imprecise. In addition, reserve estimates for properties that do not have a lengthy production
history, including the areas in which we operate, are less reliable than estimates for fields with lengthy
production histories. There can be no assurance that analysis of previous production data relating to
the Mississippian Lime or Anadarko Basins will accurately predict future production, development
expenditures or operating expenses from wells drilled and completed using modern techniques. In
addition, this data is partially based on vertically drilled wells, which may not accurately reflect
production, development expenditures or operating expenses that may result from the application of
horizontal drilling techniques.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures,
operating expenses and quantities of recoverable oil and natural gas reserves may vary from our
estimates. Any significant variance could materially affect the estimated quantities and present value of
reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect
production history, results of exploration and development, prevailing oil and natural gas prices and
other factors, many of which are beyond our control.
The development of our undeveloped reserves in our areas of operation may take longer and may require
higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not
be ultimately developed or produced.
Development of these reserves may take longer and require higher levels of capital expenditures
than we currently anticipate. Delays in the development of our reserves or increases in costs to drill
and develop such reserves will reduce the future net revenues estimated for such reserves and may
result in some projects becoming uneconomic. In addition, pursuant to existing SEC rules and
guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate
to wells scheduled to be drilled within five years of the date of booking. Accordingly, delays in the
development of such reserves, increases in capital expenditures required to develop such reserves and
changes in commodity prices may cause us to reclassify certain of our proved undeveloped reserves as
unproved reserves, which may materially adversely affect our business, results of operations and
financial condition.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would
adversely affect our business, financial condition and results of operations.
Unless we conduct successful development and exploration activities or acquire properties
containing proved reserves, our proved reserves will decline as those reserves are produced. Producing
oil and natural gas reservoirs generally are characterized by declining production rates that vary
35
depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and
production, and therefore our cash flows and income, are highly dependent on our success in efficiently
developing our current reserves and economically finding or acquiring additional recoverable reserves.
We may not be able to develop, find or acquire additional reserves to replace our current and future
production at acceptable costs. If we are unable to replace our current and future production, the value
of our reserves will decrease, and our business, financial condition and results of operations will be
adversely affected.
Our producing properties are located in the Mississippian Lime and in the Anadarko Basin, making us
vulnerable to risks associated with operating in a limited number of geographic areas.
All of our producing properties are geographically concentrated in the Mississippian Lime and
Anadarko Basin, and at December 31, 2016, all of our total estimated proved reserves were attributable
to properties located in these areas. As a result of this concentration, we may be disproportionately
exposed to the impact of regional supply and demand factors, delays or interruptions of production
from wells in these areas caused by governmental regulation, processing or transportation capacity
constraints, market limitations, availability of equipment and personnel, water shortages or other
drought related conditions or interruption of the processing or transportation of oil, NGLs or natural
gas.
Drilling locations that we have identified may not yield oil, NGLs or natural gas in commercially viable
quantities.
We describe some of our drilling locations and our plans to explore those drilling locations in this
report. Our drilling locations are in various stages of evaluation, ranging from a location which is ready
to drill to a location that will require substantial additional interpretation. It is extremely difficult to
accurately predict with any level of certainty in advance of drilling and testing whether any particular
location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to
be economically viable. The use of technologies and the study of producing fields in the same area will
not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if
present, whether oil or natural gas will be present in sufficient quantities to be economically viable.
Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive
hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the
well, resulting in a reduction in production from or abandonment of the well. If we drill additional
wells that we identify as dry holes in our current and future drilling locations, our drilling success rate
may decline and materially harm our business. In sum, the cost of drilling, completing and operating
any well is often uncertain, and new wells may not be productive.
Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties
that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent
production prior to the expiration date of leases for such locations. In addition, we may not be able to raise or
have reasonable access to the amount of capital that would be necessary to drill a substantial portion of our
identified drilling locations.
Our management team has identified and scheduled certain drilling locations as an estimation of
our future multi-year drilling activities on our existing acreage and acreage currently under option.
These drilling locations represent a significant part of our growth strategy. Our ability to drill and
develop these drilling locations depends on a number of uncertainties, including oil and natural gas
prices, the availability and cost of capital, drilling and production costs, the availability of drilling
services and equipment, drilling results, lease expirations, infrastructure and/or downstream constraints,
regulatory approvals and other factors. Because of these uncertain factors, we do not know if the
numerous drilling locations we have identified will ever be drilled or if we will be able to produce oil
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or natural gas from these or any other drilling locations. In addition, unless production is established
within the spacing units covering the undeveloped acres on which some of the potential locations are
obtained, the leases for such acreage could expire. As such, our actual drilling activities may materially
differ from those presently identified.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques.
The results of our horizontal drilling activities are subject to drilling and completion technique risks, and
actual drilling results may not meet our expectations for reserves or production. As a result, the value of our
undeveloped acreage could decline if drilling results are unsuccessful.
Risks that we face while horizontally drilling include, but are not limited to, landing our well bore
in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the
formation, running our casing the entire length of the well bore and being able to run tools and other
equipment consistently through the horizontal well bore. Risks that we face while completing our
horizontal wells include, but are not limited to, being able to fracture stimulate the planned number of
stages, being able to run tools the entire length of the well bore during completion operations and
successfully cleaning out the well bore after completion of the final fracture stimulation stage.
Ultimately, the success of these horizontal drilling and completion techniques can only be evaluated
over time as more wells are drilled in the Mississippian Lime and Anadarko Basin and production
profiles are established over a sufficiently long time period. If our horizontal drilling results in these
trends are less than anticipated, the return on our investment in this area may not be as attractive as
we anticipate and the value of our undeveloped acreage in this area could decline.
Our business depends on the availability of water and the ability to dispose of water. Limitations or
restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition,
results of operations and cash flows.
With current technology, water is an essential component of drilling and hydraulic fracturing
processes. Limitations or restrictions on our ability to secure sufficient amounts of water, or to dispose
of or recycle water after use or its production, could adversely impact our operations. In some cases,
water may need to be obtained from new sources and transported to drilling sites, resulting in
increased costs. Moreover, the introduction of new environmental initiatives and regulations related to
water acquisition, water use or waste water disposal, including produced water, drilling fluids and other
wastes associated with the exploration, development or production of hydrocarbons, could limit or
prohibit our ability to utilize hydraulic fracturing or waste water injection disposal wells.
In addition, concerns have been raised about the potential for earthquakes to occur from the use
of underground injection disposal wells, a predominant method for disposing of waste water from oil
and gas activities. As further discussed in the risk factor below, new rules and regulations may be
developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in
certain locations and/or injecting into certain formations, thereby increasing the cost of disposal in our
operations. We operate our own injection wells in addition to using injection wells owned by third
parties to dispose of waste water associated with our operations.
Compliance with environmental regulations and permit requirements governing the withdrawal,
storage, and use of water necessary for hydraulic fracturing of wells or the disposal of water may
increase our operating costs or may cause us to delay, curtail or discontinue our exploration and
development plans, which could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
37
Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of
saltwater produced in conjunction with our hydrocarbons, which could limit our ability to produce oil and gas
economically and have a material adverse effect on our business.
We dispose of large volumes of saltwater produced in conjunction with the oil and natural gas
produced from our drilling and production operations pursuant to permits issued to us by governmental
authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws
and regulations, the applicable legal requirements may be subject to change, which could result in the
imposition of more stringent operating constraints or new monitoring and reporting requirements.
As stated above under ‘‘Water Discharges and Fluid Injection’’, the adoption and implementation
of any new laws, regulations, or directives that restrict our ability to dispose of saltwater by plugging
back the depths of disposal wells, reducing the volume of oil and natural gas wastewater disposed in
such wells, restricting disposal well locations, or requiring us to shut down disposal wells, could require
the Company to cease operations at a substantial number of its oil and natural gas wells, which would
have a material adverse effect on our ability to produce oil and gas economically and, accordingly,
could materially and adversely affect our business, financial condition and results of operations.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services
could adversely affect our ability to execute our exploration and development plans within our budget and on a
timely basis.
We utilize third-party services to maximize the efficiency of our organization. The cost of oilfield
services may increase or decrease depending on the demand for services by other oil and gas
companies. There is no assurance that we will be able to contract for such services on a timely basis or
that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost
of frac crews, drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely
affect our development and exploration operations or cause us to incur significant expenditures that are
not provided for in our capital budget, which could have a material adverse effect on our business,
financial condition or results of operations.
Our business depends on transportation by truck for our oil and condensate production, and our natural gas
production depends on transportation facilities that are owned by third parties.
We transport all of our oil and condensate production by truck, which is more expensive and less
efficient than transportation via pipeline. Our natural gas production depends in part on the
availability, proximity and capacity of pipeline systems and processing facilities owned by third parties.
Federal and state regulation of oil and natural gas production and transportation, tax and energy
policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and
general economic conditions could adversely affect our ability to produce, gather and transport oil and
natural gas.
The disruption of third-party facilities due to maintenance, capacity constraints, or weather could
negatively impact our ability to market and deliver our products. We have no control over when or if
such facilities are restored or what prices will be charged. A total shut-in of production could materially
affect us due to a lack of cash flows, and if a substantial portion of the production is hedged at lower
than current market prices, those financial hedges would have to be paid from borrowings absent
sufficient cash flows.
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Our drilling and production programs may not be able to obtain access on commercially reasonable terms or
otherwise to truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to
market our oil and natural gas production.
The marketing of oil and natural gas production depends in large part on the capacity and
availability of trucks, pipelines and storage facilities, gas gathering systems and other transportation,
processing and refining facilities. Access to such facilities is, in many respects, beyond our control. If
these facilities were unavailable to us on commercially reasonable terms or otherwise, we could be
forced to shut in some production or delay or discontinue drilling plans and commercial production
following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed
and owned by third parties in order to store, process, transmit and sell our oil and natural gas
production. Our plans to develop and sell our oil and natural gas reserves could be materially and
adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and
services to us on commercially reasonable terms or otherwise. The amount of oil and gas that can be
produced is subject to limitation in certain circumstances, such as pipeline interruptions due to
scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering,
transportation, refining or processing facilities, or lack of capacity on such facilities. The curtailments
arising from these and similar circumstances may last from a few days to several months, and in many
cases, we may be provided only limited, if any, notice as to when these circumstances will arise and
their duration.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural
gas operations. Additionally we may not be insured for, or our insurance may be inadequate to protect us
against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured
events could materially and adversely affect our business, financial condition or results of operations.
Our oil and natural gas exploration and production activities are subject to all of the operating risks
associated with drilling for and producing oil and natural gas, including the possibility of:
(cid:127) environmental hazards, such as unauthorized releases of oil, natural gas, brine, well fluids, toxic
gas or other pollution into the environment, including soil and groundwater contamination;
(cid:127) abnormally pressured formations;
(cid:127) mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
(cid:127) fires, explosions and ruptures of pipelines;
(cid:127) personal injuries and death; and
(cid:127) natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial
losses as a result of:
(cid:127) injury or loss of life;
(cid:127) damage to and destruction of property, natural resources and equipment;
(cid:127) pollution and other environmental damage;
(cid:127) regulatory investigations and penalties;
(cid:127) suspension of our operations; and
(cid:127) repair and remediation costs.
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We may elect not to obtain insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks generally are not fully
insurable. The occurrence of an event that is not fully covered by insurance could have a material
adverse effect on our business, financial condition and results of operations.
Increased costs of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and
cost of capital, or increases in interest rates. Changes in any one or more of these factors could cause
our cost of doing business to increase, limit our access to capital, limit our ability to drill our identified
locations and pursue acquisition opportunities, reduce our cash flows available for drilling and place us
at a competitive disadvantage. Continuing volatility in the global financial markets may lead to an
increase in interest rates or a contraction in credit availability, impacting our ability to finance our
operations. We require continued access to capital. A significant reduction in the availability of credit
could materially and adversely affect our ability to achieve our planned growth and operating results.
The inability of our significant purchasers to meet their obligations to us may adversely affect our financial
results.
We are subject to credit risk due to concentration of our oil, NGL and natural gas receivables with
several significant purchasers. We generally do not require our purchasers to post collateral. The
inability or failure of any of our significant purchasers to meet their obligations to us or their
insolvency or liquidation may adversely affect our financial condition and results of operations.
Large competitors may be attracted to our core operating areas, which may increase our costs.
Our operations in the Mississippian Lime formation in northwestern Oklahoma and the Anadarko
Basin in the Texas panhandle and western Oklahoma may attract companies that have greater resources
than we do. These companies may be able to pay more for productive oil and natural gas properties
and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. Their presence in our areas of operations
may also restrict our access to, or increase the cost of, oil and natural gas infrastructure, drilling rigs,
equipment, supplies, personnel and oilfield services, including fracking equipment and crews. In
addition, these companies may have a greater ability to continue exploration activities during periods of
low oil and natural gas prices. Our larger competitors may be able to absorb the burden of present and
future federal, state, local and other laws and regulations more easily than we can, which would
adversely affect our competitive position. Our ability to acquire additional properties and to discover
reserves in the future will be dependent upon our ability to evaluate and select suitable properties and
to consummate transactions in a highly competitive environment. See ‘‘Business—Competition’’ for
additional discussion of the competitive environment in which we operate.
Title to the properties in which we have an interest may be impaired by title defects.
We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of
our oil and natural gas properties. The existence of title deficiencies with respect to our oil and natural
gas properties could reduce the value or render such properties worthless, which could have a material
adverse effect on our business and financial results. A portion of our acreage is undeveloped leasehold
acreage, which has a greater risk of title defects than developed acreage. Frequently, as a result of title
examinations, certain curative work may be required to correct identified title defects, and such curative
work entails time and expense. Our inability or failure to cure title defects could render some locations
undrillable or cause us to lose our rights to some or all production from some of our oil and natural
gas properties, which could have a material adverse effect on our business and financial results if a
comparable additional location to drill a development well cannot be identified.
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Future legislation may result in the elimination of certain U.S. federal income tax deductions currently
available with respect to oil and natural gas exploration and production. Additionally, future federal or state
legislation may impose new or increased taxes or fees on oil and natural gas extraction, transportation and
sales.
Potential legislation, if enacted into law, could make significant changes to U.S. federal and state
income tax laws, including the elimination of certain key U.S. federal income tax incentives currently
available to oil and 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 U.S. 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 this legislation or any other similar changes in U.S. federal and state 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 negatively affect our financial
condition and results of operations. Additionally, legislation could be enacted that increases the taxes
states impose on oil and natural gas extraction. Moreover, former President Obama proposed, as part
of the Budget of the United States Government for Fiscal Year 2017, to impose an ‘‘oil fee’’ of $10.25
on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and
imported petroleum products. The fee would be phased in evenly over five years. The adoption of this,
or similar proposals, could result in increased operating costs and/or reduced consumer demand for
petroleum products, which in turn could affect the prices we receive for our oil.
We are subject to various governmental regulations that may cause us to incur substantial costs.
From time to time, in varying degrees, political developments and federal and state laws and
regulations affect our operations. In particular, price controls, taxes and other laws relating to the oil
and natural gas industry, changes in these laws and changes in administrative regulations have affected,
and in the future could affect, oil and natural gas production, operations and economics. We cannot
predict how agencies or courts will interpret existing laws and regulations or the effect these adoptions
and interpretations may have on our business or financial condition.
Our business is subject to laws and regulations promulgated by federal, state and local authorities
relating to the exploration for, and the development, production and marketing of, oil and natural gas,
as well as safety matters. Legal requirements are frequently changed and subject to interpretation, and
we are unable to predict the ultimate cost of compliance with these requirements or their effect on our
operations. We may be required to make significant expenditures to comply with governmental laws
and regulations. The discharge of oil, natural gas or other pollutants into the air, soil or water may give
rise to significant liabilities on our part to the government and third parties and may require us to
incur substantial costs of remediation.
Our sales of oil and natural gas may expose us to extensive regulation.
The FERC, the CFTC and the FTC hold statutory authority to monitor certain segments of the
physical energy commodities markets relevant to our business. These agencies have imposed broad
regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales, if
any, of oil, NGLs and natural gas, we are required to observe the market-related regulations enforced
by these agencies.
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Our operations are subject to stringent environmental laws and regulations that may expose us to significant
costs and liabilities.
Our oil and natural gas exploration, production and development operations are subject to
numerous stringent and complex federal, regional, state, local and other laws and regulations relating to
pollution and protection of the environment, including those governing the release or disposal of
materials into the environment. Potentially applicable environmental laws include, but are not limited
to, (i) the CERCLA, and analogous state laws, which regulate the cleanup of hazardous substances that
may have been released at properties currently or formerly owned or operated by us or locations to
which we have sent wastes for disposal; (ii) the CWA and analogous state laws, which regulate the
discharge of waste and storm waters from some of our facilities; (iii) the CAA, and analogous state
laws, which impose obligations related to air emissions, including emissions limits and permitting
requirements; (iv) the RCRA, and analogous state laws, which impose requirements for the handling
and disposal of solid or hazardous waste; (v) the Endangered Species Act, and analogous state laws,
which seek to ensure that activities do not jeopardize endangered animal, fish and plant species;
(vi) the National Environmental Policy Act, which requires federal agencies to study potential
environmental impacts of a proposed federal action before it is approved; and (vii) OSHA, and
analogous state laws, which establish certain employer responsibilities, including maintenance of a
workplace free of recognized hazards. These laws and regulations may, among other things, require the
acquisition of a permit before drilling commences, require the maintenance of bonding requirements in
order to drill or operate wells, restrict the types, quantities and concentration of substances that can be
released into the environment in connection with drilling, completion and production activities, limit or
prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, and other
protected areas, impose specific standards for the plugging and abandoning of wells and impose
substantial liabilities for pollution resulting from our operations. We may be required to make
significant capital and operating expenditures to prevent releases, manage wastewater discharges and
control air emissions or perform remedial or other corrective actions at our wells and properties to
comply with the requirements of these environmental laws and regulations or the terms or conditions
of permits issued pursuant to such requirements. Failure to comply with these laws and regulations may
result in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of
investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of
our operations.
There is inherent risk of incurring significant environmental costs and liabilities in the performance
of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and
wastes, as a result of air emissions and wastewater discharges related to our operations, and because of
historical operations and waste disposal practices at our leased, operated and owned properties. Spills
or other releases of regulated substances, including such spills and releases that occur in the future,
could expose us to material losses, expenditures and liabilities or remedial obligations under applicable
environmental laws and regulations. Under certain of such laws and regulations, we could be subject to
strict, joint and several liability for the removal or remediation of previously released materials or
property contamination, regardless of whether we were responsible for the release or contamination
and even if our operations met previous standards in the industry or complied with existing applicable
laws at the time they were conducted.
Changes in environmental laws and regulations occur frequently, and any changes that result in
more stringent or costly well drilling, construction, completion or water management activities, air
emissions control or waste handling, storage, transport, disposal or cleanup requirements could require
us to make significant expenditures to attain and maintain compliance and may otherwise have a
material adverse effect on our industry in general in addition to our own results of operations,
competitive position or financial condition. For example, the EPA published a final rule on October 1,
2015 that reduces the National Ambient Air Quality Standard for ozone to between 65 and 70 ppb for
42
both the 8-hour primary and secondary standards. In addition, in May 2016, the EPA finalized rules
regarding criteria for aggregating multiple small surface sites into a single source for air-quality
permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities,
on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting
requirements. In May 2016, the EPA also issued final rules that require the reduction of volatile
organic compound and methane emissions from additional new, modified or reconstructed oil and gas
emissions sources. Since the methane and aggregation rules were published in the Federal Register
after May 31, 2016, they are potentially subject to repeal by the new Congress. Compliance with these
or other new regulations could, among other things, require installation of new emission controls on
some of our equipment, result in longer permitting timelines, and significantly increase our
expenditures and operating costs, which could adversely impact our business.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating
costs and reduced demand for the oil and natural gas we produce.
Based on the EPA’s determination that emissions of GHGs present an endangerment to public
health and the environment because emissions of such gases are contributing to warming of the earth’s
atmosphere and other climatic changes, the EPA has adopted regulations under existing provisions of
the CAA to address GHG emissions. For example, the EPA has adopted regulations that establish
pre-construction and operating permit reviews for GHG emissions from certain large stationary sources
that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities
required to obtain permits for their GHG emissions also will be required to meet ‘‘best available
control technology’’ standards that typically will be established by the states. In addition, the EPA has
adopted regulations requiring the monitoring and annual reporting of GHGs from certain sources in
the United States, including, among others, certain onshore and offshore oil and natural gas production
facilities. Most recently, in May 2016, the EPA finalized rules to reduce methane emissions from new,
modified or reconstructed sources in the oil and natural gas sector. In November 2016, the Bureau of
Land Management (‘‘BLM’’) issued final rules to reduce methane emissions from venting, flaring, and
leaks during oil and gas operations on public lands. The May 2016 and November 2016 methane rules
are potentially subject to repeal by the new Congress.
In addition, the U.S. Congress has from time to time considered adopting legislation to reduce
emissions of GHGs and a number of states have already taken legal measures to reduce emissions of
GHGs primarily through the planned development of GHG emission inventories and/or regional GHG
cap and trade programs. On an international level, the United States is one of almost 200 nations that
is party to the Paris Agreement adopted in December 2015 to reduce global GHG emissions. It is not
possible at this time to predict if or when the United States might impose restrictions on GHG
emissions as a result of this agreement. The adoption of legislation or regulatory programs to reduce
GHG emissions could require us to incur increased operating costs and could also increase the cost of
consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently,
legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our
business, financial condition and results of operations. Finally, it should be noted that some scientists
have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce
climate changes that have significant physical effects, such as increased frequency and severity of
storms, droughts and floods and other climatic events. If any such effects were to occur, they could
have an adverse effect on our financial condition and results of operations.
43
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental
reviews of such activities could result in increased costs, additional operating restrictions or delays, which
could adversely affect our production.
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. The process involves the injection of
water, sand and chemicals under pressure into the formation to fracture the surrounding rock and
stimulate production. We routinely utilize hydraulic fracturing techniques in many of our oil and
natural gas drilling and completion programs. The process is typically regulated by state oil and natural
gas commissions or similar state agencies, but several federal agencies have asserted regulatory
authority over certain aspects of the process. For example, the EPA has published permitting guidance
in February 2014 addressing the use of diesel fuel in fracturing operations; issued final CAA
regulations governing performance standards, including standards for the capture of air emissions
released during hydraulic fracturing; issued in June 2016 final effluent limit guidelines that saltwater
from shale resource extraction operations must meet before discharging to publicly owned wastewater
treatment plants; and issued in May 2014 a prepublication of its Advance Notice of Proposed
Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures
used in hydraulic fracturing. The air emissions standards issued in May 2016 and the effluent limit
guidelines issued in June 2016 are potentially subject to repeal by the new Congress. Also, the BLM
published a final rule containing disclosure requirements and other mandates for hydraulic fracturing
on federal and Indian lands in March of 2015. However, the U.S. District Court of Wyoming struck
down this rule in June 2016; the ruling is currently on appeal before the U.S. Tenth Circuit Court of
Appeals. Compliance with these requirements could increase our costs of development and production,
which costs may be significant.
From time to time, Congress has considered legislation to provide for federal regulation of
hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Moreover,
some states, including Louisiana, Texas and Oklahoma, where we operate, have adopted, and other
states are considering adopting, regulations that could impose more stringent permitting, disclosure and
well construction requirements on hydraulic fracturing operations under certain circumstances, or that
prohibit hydraulic fracturing altogether. In addition, local government may seek to adopt ordinances
within their jurisdictions regulating the time, place and manner of drilling activities in general or
hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal
restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we
could incur potentially significant added costs to comply with such requirements, and experience delays
or curtailment in the pursuit of exploration, development, or production activities. Restrictions on
hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to
produce from our reserves. In addition, there are also certain governmental reviews underway that
focus on environmental aspects of hydraulic fracturing practices which could spur initiatives to further
regulate hydraulic fracturing under the Safe Drinking Water Act (‘‘SDWA’’) or otherwise.
Our operations are dependent on our rights and ability to receive or renew the required permits and other
approvals from governmental authorities and other third parties.
Performance of our operations requires that we obtain and maintain numerous environmental,
water access and land use permits and other approvals authorizing our regulated activities. We must
renew these permits and approvals periodically, and the permits and approvals may be modified or
revoked by the issuing agency. A decision by a governmental authority or other third party to deny,
delay or restrictively condition the issuance of a new or renewed permit or other approval, or to revoke
or substantially modify an existing permit or other approval, could have a material adverse effect on
our ability to initiate or continue operations at the affected location or facility. Expansion of our
44
existing operations is also predicated on securing the necessary environmental, water access or land use
permits and other approvals, which we may not receive in a timely manner or at all.
The adoption of financial reform legislation by Congress could have an adverse effect on our ability to use
derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our
business.
In July 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall
Street Reform and Consumer Protection Act (the ‘‘DF Act’’), was enacted that establishes federal
oversight and regulation of the over-the-counter derivatives market and entities, such as us, that
participate in that market. The DF Act requires the CFTC, the SEC and other regulators to
promulgate rules and regulations implementing the DF Act. Although the CFTC has finalized certain
regulations, others remain to be finalized or implemented and it is not possible at this time to predict
when this will be accomplished.
In one of its rulemaking proceedings still pending under the DF Act, the CFTC issued on
December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts
in various commodities (including oil and gas) and for swaps that are their economic equivalents.
Under the proposed rules on position limits, certain types of hedging transactions are exempt from
these limits on the size of positions that may be held, provided that such hedging transactions satisfy
the CFTC’s requirements for certain enumerated ‘‘bona fide hedging’’ transactions or positions. As
these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this
time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory
clearing and the associated rules also will require us in connection with covered derivatives activities to
comply with clearing and trade-execution requirements or take steps to qualify for an exemption to
such requirements. Although the Company expects to qualify for the end-user exception from the
mandatory clearing requirements for swaps entered to hedge its commercial risks, the application of the
mandatory clearing and trade execution requirements to other market participants, such as swap
dealers, may change the cost and availability of the swaps that the Company uses for hedging. In
addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter
into credit support documentation and/or post initial and variation margins. Posting of collateral could
impact liquidity and reduce cash available to the Company for its needs. The DF Act may also require
the counterparties to our derivative instruments to spin off some of their derivatives activities to
separate entities, which may not be as creditworthy as the current counterparties.
The full impact of the DF Act and related regulatory requirements upon the Company’s business
will not be known until the regulations are implemented and the market for derivatives contracts has
adjusted. The DF Act and regulations could significantly increase the cost of derivative contracts,
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,
increase our exposure to less creditworthy counterparties or reduce liquidity. If we reduce our use of
derivatives as a result of the DF Act and regulations, 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 DF 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 DF Act is to lower commodity prices. Any of these consequences could have a material adverse
effect on our consolidated financial position, results of operations and cash flows.
45
Risks Relating to our Common Stock
The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute
your holding of shares of our common stock.
Pursuant to the Plan, we issued 24,994,867 shares of common stock in the reorganized Company,
4,411,765 warrants with a strike price of $24.00 per common share of the reorganized equity and
2,213,789 warrants with a strike price of $46.00 per common share of the reorganized equity.
Additionally, a total of 3,513,950 shares of common stock of the reorganized equity are reserved for
issuance under the 2016 LTIP as equity-based awards to employees, directors and certain other persons.
The exercise of equity awards, including any stock options that we may grant in the future, and
warrants, and the sale of shares of our common stock underlying any such options or the warrants,
could have an adverse effect on the market for our common stock, including the price that an investor
could obtain for their shares. Investors may experience dilution in the net tangible book value of their
investment upon the exercise of the warrants and any stock options that may be granted or issued
pursuant to the 2016 LTIP in the future.
The price and trading volume of our common stock may fluctuate significantly.
The market price of our common stock may be highly volatile and could be subject to wide
fluctuations. In addition, the trading volume of our common stock may fluctuate and cause significant
price variations to occur. Volatility in the market price of our common stock may prevent you from
being able to sell your shares at or above the price at which you were granted your shares of common
stock or above the price you paid to acquire your shares of common stock. The market price for our
common stock could fluctuate significantly for various reasons, including:
(cid:127) our new capital structure as a result of the transactions contemplated by the Plan;
(cid:127) our limited trading history subsequent to our emergence from the Chapter 11 Cases;
(cid:127) our limited trading volume;
(cid:127) the concentration of holdings of our common stock;
(cid:127) the lack of comparable historical financial information due to our adoption of fresh start
accounting;
(cid:127) actual or anticipated variations in our operating results and cash flow;
(cid:127) the nature and content of our earnings releases, announcements or events that impact our
products, customers, competitors or markets; and
(cid:127) business conditions in our markets and the general state of the securities markets and the
market for energy-related stocks, as well as general economic and market conditions.
Future sales of our common stock in the public market or the issuance of securities senior to our common
stock, or the perception that these sales may occur, could adversely affect the trading price of our common
stock and our ability to raise funds in stock offerings.
A large percentage of our shares of common stock are held by a relatively small number of
investors. Further, we entered into a registration rights agreement with certain of those investors
pursuant to which we filed a registration statement with the SEC to facilitate potential future sales of
such shares by them. Sales by us or our stockholders of a substantial number of shares of our common
stock in the public markets, or even the perception that these sales might occur (such as upon the filing
of the aforementioned registration statement), could cause the market price of our common stock to
decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions
using, our equity securities.
46
We are currently authorized to issue 250,000,000 shares of common stock and 50,000,000 shares of
preferred stock. As of December 31, 2016, we had outstanding approximately 24,994,867 shares of
common stock and warrants and options to purchase an aggregate of 6,625,554 shares of our common
stock. We have also reserved an additional 3,513,950 shares for issuance under the 2016 LTIP. The
potential issuance of such additional shares of common stock may create downward pressure on the
trading price of our common stock.
We may issue common stock or other equity securities senior to our common stock in the future
for a number of reasons, including to finance acquisitions, to adjust our leverage ratio, and to satisfy
our obligations upon the exercise of warrants and options, or for other reasons. We cannot predict the
effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or
the availability of shares of common stock or such other equity securities for future sale or issuance,
will have on the trading price of our common stock.
There may be circumstances in which the interests of our significant stockholders could be in conflict with the
interests of our other stockholders.
As of December 31, 2016, funds advised by Avenue Capital Group, Centerbridge Partners and Fir
Tree Partners held approximately 13.98%, 18.33% and 25.58%, respectively, of our post-reorganization
common stock. Circumstances may arise in which these stockholders may have an interest in pursuing
or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares
or debt, that, in their judgment, could enhance their investment in us or another company in which
they invest. Such transactions might adversely affect us or other holders of our common stock. In
addition, our significant concentration of share ownership may adversely affect the trading price of our
common shares because investors may perceive disadvantages in owning shares in companies with
significant stockholders.
ITEM 1B. UNRESOLVED STAFF COMMENTS
As of December 31, 2016, we did not have any unresolved comments from the SEC staff that were
received 180 or more days prior to year-end.
ITEM 2. PROPERTIES
Information regarding our properties is included in ‘‘Item 1. Business’’ above.
ITEM 3. LEGAL PROCEEDINGS
The information set forth under ‘‘Litigation’’ in ‘‘—Note 16. Commitments and Contingencies’’ in
the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on
Form 10-K is incorporated herein by reference.
ITEM 4. MINE SAFETY DISCLOSURES
None.
47
PART II.
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market for Registrant’s Common Equity
In connection with our reorganization and emergence from bankruptcy, all equity interests
outstanding prior to emergence October 21, 2016 were cancelled. On the Effective Date, we issued
24,687,500 shares of common stock of the reorganized Company. On November 8, 2016, the Company
issued 12,400 shares of common stock to employees and non-employee directors, which vested
immediately upon issuance. On November 9, 2016, we issued an additional 294,967 shares of common
stock of the reorganized Company pursuant to the Plan. We will issue 17,533 additional common
shares, with respect to general unsecured claims, pursuant to the Plan in a future distribution. The total
authorized capital stock of the reorganized equity consists of 250,000,000 shares of common stock and
50,000,000 shares of preferred stock. The 2016 LTIP was established under which 10.0% of the equity
in the reorganized equity (on a fully-diluted/fully-distributed basis) was reserved for grants to be made
from time to time to the directors, officers, and other members of management of the reorganized
Company. For further discussion of the Plan, please see ‘‘—Note 2. Emergence from Voluntary
Reorganization under Chapter 11 Proceedings’’ in the Notes to Consolidated Financial Statements set
forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Prior to October 24, 2016, our common stock traded on the OTC Pink market under the symbol
‘‘MPOY’’ and, on October 24, 2016, our new common stock began trading on the NYSE MKT under
the symbol ‘‘MPO’’. The high and low sales prices per share are as follows:
2016
Price Range
High
Low
Fourth Quarter (from October 24) . . . . . . . . . . . . . . . . . . . . . . . .
$25.00
$17.01
On March 27, 2017, the last sales price of our common stock, as reported on the NYSE MKT, was
$18.50 per share.
As of March 27, 2017, there were 24,994,867 shares of common stock outstanding.
Holders
The number of shareholders of record of our common stock was one on March 27, 2017.
Dividends
We have not paid any cash dividends since inception. In addition, our Exit Facility limits and
restricts our ability to pay dividends on our capital stock. We currently intend to retain all future
earnings for the development and growth of our business, and we do not anticipate declaring or paying
any cash dividends to holders of our common stock in the foreseeable future.
48
Stock Performance Graph
The following performance graph and related information shall not be deemed ‘‘soliciting
material’’ or to be filed with the SEC, such information shall not be incorporated by reference into any
future filing under the Securities Act or Exchange Act, except to the extent that we specifically request
that such information be treated as ‘‘soliciting material’’ or specifically incorporate such information by
reference into such a filing.
The performance graph below shows the cumulative total return to our common stockholders from
the date our common stock began trading on the NYSE MKT (October 24, 2016) through
December 31, 2016, as compared to the cumulative total returns on the Standard and Poor’s 500 Index
(‘‘S&P 500’’) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (‘‘S&P
O&G E&P’’) for the same period of time. The comparison was prepared on the following assumptions:
(cid:127) $100 was invested in our common stock at its opening price of $19.00 per share and invested in
the S&P 500 and the S&P O&G E&P on October 24, 2016 at the closing price on such date;
and
(cid:127) Dividends, if any, are reinvested.
$115.00
$110.00
$105.00
$100.00
$95.00
$90.00
$85.00
$80.00
Oct-16
Nov-16
Dec-16
MPO
S&P 500
S&P 500 O&G E&P
24MAR201706494021
49
ITEM 6. SELECTED FINANCIAL DATA
The following tables set forth our selected financial data over the five-year period ended
December 31, 2016. The information in the table below has been derived from our consolidated
financial statements and the notes thereto included in Item 15 in this Annual Report on Form 10-K.
This information should be read in conjunction with, and is qualified in its entirety by, the more
detailed information our consolidated financial statements set forth in Item 15 of this Annual Report
on Form 10-K.
Presented below is our historical financial data for the periods indicated. The historical financial
data for the Successor Period and Predecessor Period, as well as December 31, 2015 and 2014, are
derived from our audited consolidated financial statements and the notes thereto included in Item 15
in this Annual Report on Form 10-K. The historical financial data for the years ended December 31,
2013 and 2012 are derived from our audited financial statements not included in this Annual Report on
Form 10-K. As discussed in ‘‘—Note 3. Fresh Start Accounting’’ in the Notes to the Consolidated
Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, upon our
emergence on the Effective Date, we adopted fresh start accounting as required by US GAAP. We
applied fresh start accounting as of October 21, 2016. As a result of the application of fresh start
accounting, as well as the effects of the implementation of the Plan, our consolidated financial
statements on or after the Effective Date are not comparable with our consolidated financial
statements prior to that date.
Successor
Predecessor
For the Period
October 21,
2016
through
December 31,
2016
For the Period
January 1,
2016
through
October 20,
2016
December 31,
2015(1)
2014(2)
2013(3)
2012(4)
48,525
9,930
$
193,228 $
365,145 $ 794,183 $
1,323,079
(1,797,195)
116,929
469,506 $ 247,673
(343,985) (150,097)
9,650
1,306,557
(1,798,143)
67,271
(359,574) (156,597)
0.39
$
122.74 $
(232.74) $
10.13 $
(54.68) $
(26.11)
(in thousands, except per share
amounts)
Income Statement Data
Total revenues . . . . . . . . . . . $
Net income (loss) . . . . . . . . .
Net income (loss) attributable
to common shareholders(5)
Net income (loss) per share
attributable to common
shareholders(6) . . . . . . . . .
Basic and diluted . . . . . . . . $
Other Financial Data
Net cash provided by
operating activities . . . . . . . $
23,644
$
61,997 $
213,383 $ 351,544 $
237,588 $ 145,019
Net cash used in investing
activities . . . . . . . . . . . . . .
(23,346)
(133,307)
(294,556) (404,264) (1,204,332) (781,378)
Net cash provided by
financing activities . . . . . . .
Adjusted EBITDA(7) . . . . . .
—
26,766
66,757
93,465
150,709
315,340
31,114
474,098
981,029
330,759
647,893
144,619
(1) The year ended December 31, 2015 reflects the Dequincy Divestiture, which closed on April 21,
2015. For a discussion of significant divestitures, see ‘‘—Note 8. Acquisition and Divestitures of Oil
and Gas Properties’’ in the Notes to the Consolidated Financial Statements set forth in Part IV,
Item 15 of this Annual Report on Form 10-K.
(2) The year ended December 31, 2014 reflects the sale of all ownership interest in developed and
undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana (‘‘Pine Prairie
50
Disposition’’), which closed on May 1, 2014. For a discussion of significant divestitures, see
‘‘—Note 8. Acquisition and Divestitures of Oil and Gas Properties’’ in the Notes to the
Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on
Form 10-K.
(3) The year ended December 31, 2013 reflects the Anadarko Basin Acquisition, which closed on
May 31, 2013.
(4) The year ended December 31, 2012 reflects the Eagle Property Acquisition, which closed on
October 1, 2012.
(5) The years ended December 31, 2015, 2014, 2013 and 2012 include the effect of an undeclared
Series A Preferred Stock dividend of $0.9 million, $10.4 million, $15.6 million and $6.5 million,
respectively, which was paid in shares upon the mandatory conversion of the Preferred Stock into
common shares on September 30, 2015. See ‘‘—Note 11. Preferred Stock’’ in the Notes to the
Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on
Form 10-K.
(6) The net loss per share attributable to common shareholders for the year ended December 31, 2012
is on a pro forma basis, as our common stock did not trade for the entirety of 2012 (trading began
on the NYSE on April 20, 2012).
(7) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a
reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating
activities, see ‘‘Non GAAP Financial Measures and Reconciliations’’ below.
Presented below is our historical financial data as of the dates indicated. The historical balance
sheet data as of December 31, 2016 and December 31, 2015 are derived from our audited consolidated
financial statements and the notes thereto included in Item 15 in this Annual Report on Form 10-K.
The historical balance sheet data as of December 31, 2014, 2013 and 2012 are derived from our
audited financial statements not included in this Annual Report on Form 10-K.
(in thousands, except per share amounts)
Balance Sheet Data
Cash and cash equivalents . . . . . . . . . $
Net property and equipment
. . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . .
Total debt, including debt classified as
current(5) . . . . . . . . . . . . . . . . . . .
Stockholders’ equity (deficit) . . . . . . .
Weighted average number of common
shares outstanding . . . . . . . . . . . . .
Successor
December 31,
2016
Predecessor
December 31,
2015(1)
2014(2)
2013(3)
2012(4)
76,838
631,595
760,939
$
81,093
523,869
679,167
$
11,557
2,123,116
2,447,175
$
33,163
2,094,894
2,308,637
$
18,878
1,567,408
1,665,927
128,059
561,814
1,890,944
(1,326,066)
1,706,532
465,862
1,667,680
339,999
675,917
677,469
25,009
7,726
6,644
6,576
5,997
(1) The year ended December 31, 2015 reflects the Dequincy Divestiture, which closed on April 21,
2015. For a discussion of significant divestitures, see ‘‘—Note 8. Acquisition and Divestitures of Oil
and Gas Properties’’ in the Notes to the Consolidated Financial Statements set forth in Part IV,
Item 15 of this Annual Report on Form 10-K.
(2) The year ended December 31, 2014 reflects the Pine Prairie Disposition, which closed on May 1,
2014. For a discussion of significant divestitures, see ‘‘—Note 8. Acquisition and Divestitures of Oil
and Gas Properties’’ in the Notes to the Consolidated Financial Statements set forth in Part IV,
Item 15 of this Annual Report on Form 10-K.
51
(3) The year ended December 31, 2013 reflects the Anadarko Basin Acquisition, which closed on
May 31, 2013.
(4) The year ended December 31, 2012 reflects the Eagle Property Acquisition, which closed on
October 1, 2012.
(5) At December 31, 2015, we were in default under our RBL. As a result, our debt was classified as
current as of December 31, 2015.
Non-GAAP Financial Measures and Reconciliations
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management
and external users of our consolidated financial statements, such as industry analysts, investors, lenders
and rating agencies.
We define Adjusted EBITDA as earnings before interest income and expense, income taxes,
depreciation, depletion and amortization, property impairments, asset retirement obligation accretion,
unrealized derivative gains and losses, reorganization items and non-cash share-based compensation
expense. Adjusted EBITDA is not a measure of net income or cash flows as determined by United
States generally accepted accounting principles, or US GAAP. We believe that Adjusted EBITDA is
useful because it allows us to more effectively evaluate our operating performance and compare the
results of our operations from period to period without regard to our financing methods or capital
structure. We exclude items such as property and inventory impairments, asset retirement obligation
accretion, unrealized derivative gains and losses and non-cash share-based compensation expense, net
of amounts capitalized, from net income in arriving at Adjusted EBITDA because these amounts can
vary substantially from company to company within our industry depending upon accounting methods
and book values of assets, capital structures and the method by which the assets were acquired.
Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income
or cash flows from operating activities as determined in accordance with US GAAP or as an indicator
of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are
significant components in understanding and assessing a company’s financial performance, such as a
company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of
which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be
comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is
a widely followed measure of operating performance and may also be used by investors to measure our
ability to meet debt service requirements.
52
The following table presents a reconciliation of the non-GAAP financial measure of Adjusted
EBITDA to the US GAAP measure of net income (loss) and net cash provided by operating activities,
respectively (in thousands).
Successor
For the Period
October 21,
2016 Through
December 31,
2016
For the Period
January 1,
2016 Through
October 20,
2016
Predecessor
December 31,
2015
2014
2013
2012
Adjusted EBITDA
reconciliation to net
income (loss):
Net income (loss)
. . . . . . .
Depreciation, depletion and
amortization . . . . . . . . .
Impairment in carrying
value of oil and gas
properties . . . . . . . . . . .
Loss on sale/impairment of
field equipment inventory
(Gains) Losses on
commodity derivative
contracts—net . . . . . . . .
Net cash received (paid) for
commodity derivative
contracts not designated
as hedging instruments . .
Reorganization items, net . .
Income tax expense
(benefit) . . . . . . . . . . . .
Interest income . . . . . . . . .
Interest expense—net of
amounts capitalized
(Predecessor Period
excludes interest expense
of $89.5 million on senior
and secured notes) . . . . .
Asset retirement obligation
accretion . . . . . . . . . . . .
Share-based compensation,
net of amounts capitalized
$
9,930
$
1,323,079
$(1,797,195) $ 116,929
$(343,985) $(150,097)
12,974
62,302
198,643
269,935
250,396
125,561
—
—
—
—
—
—
—
743
210
2,909
232,108
1,625,776
86,471
453,310
1,997
4,056
615
—
—
(40,960)
(139,189)
44,284
11,158
—
—
—
(1,594,281)
167,669
—
(18,332)
—
(17,585)
—
(15,825)
—
—
(81)
(9,641)
(115)
6,395
(39)
(146,529)
(33)
157,886
(245)
66,360
163,148
137,548
83,138
12,999
1,414
2,564
1,610
4,408
1,706
8,618
1,435
5,713
723
2,459
Adjusted EBITDA . . . . . . .
$
26,766
$
93,465
$
315,340
$ 474,098
$ 330,759
$ 144,619
53
Successor
For the Period
October 21,
2016 Through
December 31,
2016
For the Period
January 1,
2016 Through
October 20,
2016
Predecessor
December 31,
2015
2014
2013
2012
$
$
23,644
2,442
—
61,997
(33,365)
(81)
$213,383
(58,293)
(115)
$351,544
(7,098)
(39)
$237,588
16,021
(33)
$145,019
(11,624)
(245)
743
—
(63)
71,075
(1,574)
171,681
—
137,548
—
83,138
—
12,999
—
(4,587)
(11,316)
(7,857)
(5,955)
(1,530)
Adjusted EBITDA reconciliation
to net cash provided by
operating activities:
Net cash provided by operating
activities . . . . . . . . . . . . . . . .
Changes in working capital(1) . . .
Interest income . . . . . . . . . . . .
Interest expense, net of amounts
capitalized and accrued but not
paid (Predecessor Period
excludes interest expense of
$89.5 million on senior and
secured notes)(2) . . . . . . . . . .
Operating lease abandonment(3) .
Amortization of deferred
financing costs . . . . . . . . . . . .
Adjusted EBITDA . . . . . . . . . . .
$
26,766
$
93,465
$315,340
$474,098
$330,759
$144,619
Acquisition and transaction costs .
Debt restructuring costs and
advisory fees . . . . . . . . . . . . .
Adjusted EBITDA before
—
—
—
330
4,129
11,803
14,884
7,590
36,141
—
—
—
transaction and advisory costs .
$
26,766
$
101,055
$351,811
$478,227
$342,562
$159,503
(1) Changes in working capital for all periods have been adjusted for the loss on sale/impairment of field
equipment inventory and current taxes. Additionally, the 2015 change in working capital includes $34.4 million
of restructuring transaction costs that were paid during the year.
(2)
Interest expense for the Predecessor Period excludes $3.5 million in accrued paid-in-kind interest on the Third
Lien Notes and $8.2 million in amortization of deferred gain on troubled debt restructuring. Interest expense
for the year ended December 31, 2015 excludes $6.4 million in accrued paid-in-kind interest on the Third
Lien Notes and $14.9 million in amortization of deferred gain on troubled debt restructuring. See ‘‘—Note 10.
Debt’’ in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual
Report on Form 10-K.
(3) Operating lease abandonment for the Predecessor Period includes a $1.6 million decrease in the liability
previously recorded for the abandonment of the Houston office lease.
54
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be
read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this
Annual Report on Form 10-K. The following discussion contains ‘‘forward-looking statements’’ that are
based on management’s current expectations, estimates and projections about our business and operations,
and involves risks and uncertainties. Our actual results may differ materially from those currently anticipated
and expressed in such forward-looking statements as a result of a number of factors, including those we
discuss under ‘‘Risk Factors,’’ ‘‘Cautionary Note Regarding Forward-Looking Statements’’ and elsewhere in
this Annual Report on Form 10-K.
Overview
We are an independent exploration and production company focused on the application of modern
drilling and completion techniques in oil and liquids-rich basins in the onshore United States. Our
operations are primarily focused on exploration and production activities in the Mississippian Lime and
Anadarko Basin.
Our current activities are focused on the evaluation and development of our current acreage
position to maximize the value of our primarily oil and liquids rich resource potential in our core areas
of operations and identifying potential expansion opportunities in those areas, specifically the
Mississippian Lime. During 2016, we earned approximately 24,248 net (45,440 gross) prospective acres
through various farm-in agreements and plan to continue to utilize such agreements in the future. For
2017, we plan to allocate substantially all of our drilling and completions capital budget to development
activities in the Mississippian Lime area based on the stronger economic returns expected from these
assets in the current commodity price and cost environment.
As of December 31, 2016, our properties consisted of approximately 225,000 net acres of
leasehold, with 846 gross productive wells, 68% of which we operate, and in which we held an average
working interest of approximately 76%. As of December 31, 2016, our estimated net proved reserves
were 176,988 MMBoe, of which 56% was oil or NGLs and 39% was proved developed. For the
Successor Period and Predecessor Period, our properties had aggregate net daily production of
approximately 24,971 Boe/d and 29,816 Boe/d, respectively.
On April 21, 2015, we closed on the sale of certain of our oil and gas properties in Beauregard
and Calcasieu Parishes, Louisiana, for approximately $44.0 million, before customary post-closing
adjustments. We have no proved reserves in the Gulf Coast (or state of Louisiana) as of December 31,
2016 or 2015.
As discussed in ‘‘—Note 3. Fresh Start Accounting’’ in the Notes to the Consolidated Financial
Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, upon our emergence
from the Chapter 11 cases on October 21, 2016, we adopted fresh start accounting as required by
US GAAP. As a result of the application of fresh start accounting, as well as the effects of the
implementation of the Plan, our consolidated financial statements on or after October 21, 2016, are not
comparable with our consolidated financial statements prior to that date. References to ‘‘Successor
Period’’ relate to the financial position and results of operations for the period October 21, 2016
through December 31, 2016 and references to ‘‘Predecessor Period’’ refer to the financial position and
results of operations of the Company from January 1, 2016 through October 20, 2016.
55
Recent Developments
Emergence from Chapter 11 Bankruptcy
On the Petition Date, we filed voluntary petitions for reorganization under Chapter 11 of the
Bankruptcy Code in the United States Bankruptcy Court. Our Chapter 11 cases were jointly
administered under the case styled In re Midstates Petroleum Company, Inc., et al., Case No. 16-32237.
On September 28, 2016, the Bankruptcy Court entered the Confirmation Order, which approved
and confirmed the Plan. On the Effective Date, we satisfied the conditions to effectiveness set forth in
the Confirmation Order and in the Plan, and the Plan therefore became effective in accordance with its
terms and we emerged from bankruptcy.
Plan of Reorganization
Pursuant to the confirmed Plan, the significant transactions that occurred upon the Effective Date
were as follows:
(cid:127) Substantial Deleveraging of the Balance Sheet: The permanent pay-down of $81.3 million of our
RBL, with a $170.0 million Exit Facility established upon the Effective Date, (ii) the pay-down
of $60.0 million of our Second Lien Notes in cash, and (iii) the conversion into equity of all of
our remaining debt junior to the RBL;
(cid:127) Credit Facility Claims: Holders of Credit Facility Claims received their pro rata share of
approximately $81.3 million in cash and the RBL was superseded, pursuant to the Plan, by the
Exit Facility, as further described below;
(cid:127) Second Lien Notes Claims: Holders of Second Lien Notes Claims received their pro rata share
of (i) 96.25% of the reorganized equity in the form of common stock and (ii) a cash payment of
$60.0 million;
(cid:127) Third Lien Notes Claims: Holders of Third Lien Notes Claims, pursuant to the Second/Third
Lien Plan Settlement, received their pro rata share of 2.5% of the reorganized equity in the
form of common stock and warrants to acquire 4,411,765 shares of common stock at a strike
price of $24.00 per common share with an expiration date 42 months after the Effective Date;
(cid:127) Unsecured Claims: Unsecured Notes Claims and the Holders of other general unsecured claims
received their pro rata share of 1.25% of reorganized equity in the form of common stock and
warrants to acquire 2,213,789 shares of common stock at a strike price of $46.00 per common
share with an expiration date 42 months after the Effective Date;
(cid:127) Existing Equity: All existing equity interests were extinguished and existing equity holders did
not receive any consideration in respect of their equity interests;
(cid:127) New Equity: On the Effective Date, we issued 24,687,500 shares of common stock of the
reorganized equity. On November 9, 2016, we issued an additional 294,967 shares of common
stock of the reorganized equity pursuant to the Plan. We will issue 17,533 additional common
shares, with respect to general unsecured claims, pursuant to the Plan in a future distribution.
The total authorized reorganized capital stock consists of 250,000,000 shares of common stock
and 50,000,000 shares of preferred stock;
(cid:127) Exit Facility: Our RBL, which was redetermined with a borrowing base of $170.0 million in April
2016, was superseded, pursuant to the Plan, by the Exit Facility. The Exit Facility has an initial
borrowing base of $170.0 million with no borrowing base redeterminations to occur until April
2018 (provided certain conditions are met) and semiannual borrowing base redeterminations
each year on April 1 and October 1 thereafter. Until April 2018, unless the borrowing base is
redetermined earlier, the amount available to be drawn under the Exit Facility is reduced by
56
$40.0 million, and thereafter, we must maintain liquidity (as defined therein) equal to at least
20.0% of the effective borrowing base. In connection therewith, on the Effective Date, we made
an additional payment of $40.0 million to lenders under our Exit Facility; and
(cid:127) Long-Term Incentive Plan: The LTIP was established under which 10.0% of the reorganized
equity (on a fully-diluted/fully-distributed basis) was reserved for grants to be made from time to
time to directors, officers, and other members of management.
Fresh Start Accounting
Upon our emergence on the Effective Date, we adopted fresh start accounting as required by
US GAAP. We qualified for fresh start accounting because (i) the holders of existing voting shares of
the pre-emergence debtor-in-possession received less than 50% of the voting shares of the
post-emergence successor entity and (ii) the reorganization value of our assets immediately prior to
confirmation was less than the post-petition liabilities and allowed claims.
As discussed in ‘‘—Note 3. Fresh Start Accounting’’ in the Notes to the Consolidated Financial
Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, we applied fresh start
accounting as of October 21, 2016. Adopting fresh start accounting results in a new reporting entity for
financial reporting purposes with no beginning retained earnings or deficit. The cancellation of all
existing shares outstanding on the Effective Date and issuance of new shares in the reorganized
Company caused a related change of control under US GAAP.
As a result of the application of fresh start accounting, as well as the effects of the implementation
of the Plan, our consolidated financial statements on or after October 21, 2016, are not comparable
with our consolidated financial statements prior to that date.
Stock Listing
Our common stock was listed on the NYSE on April 25, 2012 through February 3, 2016 under the
symbol ‘‘MPO’’. On February 3, 2016, our stock was delisted by the NYSE and began trading on the
OTC Pink market under the symbol ‘‘MPOY’’ through October 21, 2016. On October 21, 2016, in
connection with our emergence from Chapter 11, our existing common shares traded under the symbol
MPOY were cancelled. On October 24, 2016, our newly issued shares of common stock in the
reorganized equity were listed and began trading on the NYSE MKT under the symbol ‘‘MPO’’.
Results of Operations
Oil, NGLs and Natural Gas Revenue
Oil, NGLs and Natural Gas
Our revenues are derived from the sale of oil and natural gas production, as well as the sale of
NGLs that are extracted from our high Btu content natural gas. Our oil and gas revenues do not
include the effects of derivatives, and may vary significantly from period to period as a result of
changes in production volumes or commodity prices. Prices for oil, NGLs and natural gas fluctuate
widely and affect:
(cid:127) the amount of our cash flows available for capital expenditures;
(cid:127) our ability to borrow and raise additional capital;
(cid:127) the quantity of oil, NGLs and natural gas we can economically produce; and
(cid:127) our revenues and profitability.
57
Average market prices for oil and NGLs decreased significantly in the last part of 2014 and
continue to remain depressed compared to previous highs. For a description of factors that may impact
future commodity prices, please read ‘‘Risk Factors—Risks Related to the Oil and Natural Gas
Industry and our Business.’’
The following table sets forth information regarding our oil, natural gas and NGL revenues for the
Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014 (in thousands):
Revenues for the year ended December 31, 2014 . . . . .
Changes due to volumes . . . . . . . . . . . . . . . . . . . . .
Changes due to price . . . . . . . . . . . . . . . . . . . . . . . .
Revenues for the year ended December 31, 2015 . . . . .
Changes due to volumes . . . . . . . . . . . . . . . . . . . . .
Changes due to price . . . . . . . . . . . . . . . . . . . . . . . .
Crude Oil
Natural Gas
NGLs
Total
$ 466,655
(15,923)
(233,096)
$ 217,636
(69,486)
(35,522)
$
$
99,204
8,100
(40,481)
66,823
(10,827)
(7,678)
$ 87,771
878
(50,400)
$ 38,249
(7,708)
(3,068)
$ 653,630
(6,945)
(323,977)
$ 322,708
(88,021)
(46,268)
Revenues for the Predecessor Period . . . . . . . . . . . . . .
$ 112,628
$
48,318
$ 27,473
$ 188,419
Changes due to volumes . . . . . . . . . . . . . . . . . . . . .
Changes due to price . . . . . . . . . . . . . . . . . . . . . . . .
(113,672)
26,593
(50,479)
15,796
(29,379)
10,297
(193,530)
52,686
Revenues for the Successor Period . . . . . . . . . . . . . . . .
$ 25,549
$
13,635
$ 8,391
$ 47,575
Oil, Natural Gas and NGL Pricing
The following table sets forth information regarding average realized sales prices for the Successor
Period, Predecessor Period and the years ended December 31, 2015 and 2014:
Successor
Predecessor
For the Period
October 21, 2016
Through
For the Period
January 1, 2016
Through
Years Ended December 31,
December 31, 2016 October 20, 2016
2015
% Change
2014
AVERAGE SALES PRICES:
Oil, without realized derivatives
(per Bbl) . . . . . . . . . . . . . . . . . . . . $
Oil, with realized derivatives (per Bbl) $
Natural gas liquids, without realized
derivatives (per Bbl) . . . . . . . . . . . . $
Natural gas liquids, with realized
derivatives (per Bbl) . . . . . . . . . . . . $
Natural gas, without realized
derivatives (per Mcf) . . . . . . . . . . . $
Natural gas, with realized derivatives
(per Mcf) . . . . . . . . . . . . . . . . . . . $
Crude Oil Prices
46.96
46.96
19.55
19.55
2.76
2.76
$
$
$
$
$
$
37.99 $45.40
37.99 $74.74
(50)% $90.71
(15)% $87.40
14.22 $15.46
(57)% $36.31
14.22 $15.46
(58)% $36.40
2.08 $ 2.35
(41)% $ 3.97
2.08 $ 3.30
(16)% $ 3.91
The majority of our crude oil production is sold at prevailing market prices with an adjustment for
transportation and quality. The market pricing for oil fluctuates in response to many factors that are
outside of our control such as supply and demand fluctuations, pipeline and refinery outages, weather
patterns and global events and economics.
Historically, we utilized fixed price swaps to manage the impact of changing crude prices. All of
our derivatives expired at December 31, 2015 and we did not enter into additional derivatives for 2016.
58
Subsequent to December 31, 2016, we entered into various oil derivative contracts that extend
through March 2018, which are summarized as follows:
Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended
March 31,
2017
June 30,
2017
September 30, December 31,
2017
2017
March 31,
2018
NYMEX WTI
Fixed swaps
Hedge position (Bbls) . . . . . .
Weighted average strike price . $
105,500
227,500
207,000
207,000
55.17 $
55.12 $
55.29 $
55.29 $
Collars
Hedge position (Bbls) . . . . . .
Weighted average ceiling price $
Weighted average floor price . $
74,500
136,500
59.68 $
50.00 $
59.73 $
50.00 $
46,000
60.00 $
50.00 $
46,000
60.00 $
50.00 $
—
—
—
—
—
Three way collars
Hedge position (Bbls) . . . . . .
Weighted average ceiling price $
Weighted average floor price . $
Weighted average sub-floor
price . . . . . . . . . . . . . . . . . $
Natural Gas Prices
—
— $
— $
— $
—
— $
— $
115,000
115,000
62.80 $
50.00 $
62.80 $
50.00 $
135,000
63.50
50.00
— $
40.00 $
40.00 $
40.00
Natural gas prices are subject to variances based on local supply and demand conditions as well as
rapidly evolving market conditions. Our current natural gas sales contracts are based upon index pricing
that varies widely as a result of many factors, such as geography and supply and demand. Our natural
gas is sold on a monthly weighted average sales price utilizing a combination of first of month index
and daily index pricing for a given period.
Historically, we utilized fixed price swaps to manage the impact of changing natural gas prices. All
of our derivatives expired at December 31, 2015 and we did not enter into additional derivatives for
2016.
Subsequent to December 31, 2016, we entered into various natural gas derivative contracts that
extend through March 2018, which are summarized as follows:
Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended
March 31,
2017
June 30,
2017
September 30, December 31,
2017
2017
March 31,
2018
NYMEX HENRY HUB
Fixed swaps
Hedge position (MMBtu) . . . .
Weighted average strike price . $
— 2,912,000
— $
3.38 $
2,944,000
992,000
3.38 $
3.38 $
Collars
Hedge position (MMBtu) . . . .
Weighted average ceiling price $
Weighted average floor price . $
1,298,000
3.70 $
3.10 $
Three way collars
Hedge position (MMBtu) . . . .
Weighted average ceiling price $
Weighted average floor price . $
Weighted average sub-floor
price . . . . . . . . . . . . . . . . . $
—
— $
— $
— $
59
—
— $
— $
—
— $
— $
— $
—
—
—
—
—
—
— $
— $
—
— $
— $
—
— $
— $
610,000
4.30 $
3.25 $
900,000
4.30
3.25
— $
2.50 $
2.50
NGL Prices
Our NGL production is sold under contracts with prices at market indices less the costs for
transportation and fractionation. The market price of our NGL production, which primarily consists of
ethane, propane, butane, iso-butane and natural gasoline, can be impacted by local market conditions,
such as fractionation availability, and business conditions of the end users of such NGL products, such
as chemical companies, plastic manufacturers and propane dealers.
Oil Revenues
Successor Period
For the Successor Period, our oil sales revenues were $25.5 million. Our oil revenue was comprised
of $20.5 million from our Mississippian Lime assets and $5.0 million from our Anadarko Basin assets.
Predecessor Period
For the Predecessor Period, our oil sales revenues were $112.6 million. Our oil revenue was
comprised of $91.5 million from our Mississippian Lime assets and $21.1 million from our Anadarko
Basin assets.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
Our oil sales revenues decreased by $249.1 million, or 53%, to $217.6 million during the year
ended December 31, 2015 as compared to $466.7 million for the year ended December 31, 2014. Lower
revenue was primarily the result of decreases in oil prices for the year ended December 31, 2015 as
compared to the year ended December 31, 2014. Of the $217.6 million in total oil sales revenues,
$169.2 million was our Mississippian Lime assets, $43.7 million was from our Anadarko Basin assets
and $4.7 million was from our Gulf Coast assets.
Natural Gas Revenues
Successor Period
For the Successor Period, our natural gas sales revenues were $13.6 million. Our natural gas
revenue was comprised of $11.8 million from our Mississippian Lime assets and $1.8 million from our
Anadarko Basin assets.
Predecessor Period
For the Predecessor Period, our natural gas sales revenues were $48.3 million. Our natural gas
revenue was comprised of $42.6 million from our Mississippian Lime assets and $5.7 million from our
Anadarko Basin assets.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
Our natural gas sales revenues decreased by $32.4 million, or 33%, to $66.8 million during the year
ended December 31, 2015 as compared to $99.2 million for the year ended December 31, 2014. Lower
revenue was primarily the result of decreases in natural gas prices for the year ended December 31,
2015 as compared to the year ended December 31, 2014. Of the $66.8 million in total natural gas sales
revenues, $56.5 million was from our Mississippian Lime assets, $10.1 million was from our Anadarko
Basin assets and $0.2 million was from our Gulf Coast assets.
60
NGL Revenues
Successor Period
For the Successor Period, our NGLs sales revenues were $8.4 million. Our NGL revenue was
comprised of $6.8 million from our Mississippian Lime assets and $1.6 million from our Anadarko
Basin assets.
Predecessor Period
For the Predecessor Period, our NGLs sales revenues were $27.5 million. Our NGL revenue was
comprised of $22.5 million from our Mississippian Lime assets and $5.0 million from our Anadarko
Basin assets.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
Our NGLs sales revenues decreased by $49.6 million, or 56%, to $38.2 million during the year
ended December 31, 2015 as compared to $87.8 million for the year ended December 31, 2014. Lower
revenue was primarily the result of decreases in NGLs prices for the year ended December 31, 2015 as
compared to the year ended December 31, 2014. Of the $38.2 million in total NGLs revenues,
$30.7 million was from our Mississippian Lime assets, $7.0 million was from our Anadarko Basin assets
and $0.5 million was from our Gulf Coast assets.
Gains/Losses on Commodity Derivative Contracts—Net
We, at times, utilize commodity derivatives to reduce our exposure to fluctuations in the prices of
oil, NGLs and natural gas. Accordingly, our income statements reflect (i) the recognition of unrealized
gains and losses associated with our open derivative contracts as commodity prices change and
commodity derivatives contracts expire or new ones are entered into, and (ii) our realized gains or
losses on the settlement of these commodity derivative contracts. Unrealized gains and losses result
from changes in market valuations of derivatives as future commodity price expectations change
compared to the contract prices on the derivatives. If the expected future commodity prices increase
compared to the contract prices on the derivatives, unrealized losses are recognized. Conversely, if the
expected future commodity prices decrease compared to the contract prices on the derivatives,
unrealized gains are recognized. Since we have elected not to apply hedge accounting to our
derivatives, we reflect the unrealized and realized gains and losses in our current income statement
periods based on the mark-to-market (‘‘MTM’’) value at the end of each month. Cash flows associated
with derivative financial instruments are reflected in cash flows from operations in our consolidated
statement of cash flows. We had no open derivative contracts at December 31, 2015 or December 31,
2016. However, subsequent to December 31, 2016, we did enter into various derivative contracts for
2017 and the first quarter of 2018.
61
The following table sets forth the components of our realized gain on commodity derivative
contracts, net in our consolidated statements of operations (in thousands):
Successor
For the Period
October 21,2016
Through
For the Period
January 1, 2016
Through
Predecessor
Year Ended December 31,
December 31, 2016 October 20, 2016
2015
2014
Realized
Gain
Realized
Gain
Realized
Gain
Average
Realized
Sales Price Gain/(Loss)
Average
Sales Price
Oil commodity contracts $
Natural gas liquids
commodity contracts .
Natural gas commodity
contracts . . . . . . . . . .
Total cash receipts
— $
— $140,656
$
74.74
$ (17,060) $
87.40
—
—
—
—
—
—
217
36.40
27,013
3.30
(1,489)
3.91
(payments) . . . . . . . . $
— $
— $167,669
$ (18,332)
Cash settlements, as presented in the table above, represent realized gains/losses related to our
derivative instruments. In addition to cash settlements, we also recognize fair value changes on our
derivative instruments in each reporting period. The changes in fair value result from new positions and
settlements that may occur during each reporting period, as well as the relationships between contract
prices and the associated forward curves. At December 31, 2016, we had no derivative instruments.
Other Revenues
Successor Period
For the Successor period, other revenues were $1.0 million. Other revenue for the Successor
Period was primarily comprised of fees charged to outside working interest owners for salt water
disposal.
Predecessor Period
For the Predecessor Period, other revenues were $4.8 million. Other revenue for the Predecessor
Period was primarily comprised of fees charged to outside working interest owners for salt water
disposal.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
Our other revenues were $1.5 million and $1.4 million for the years ended December 31, 2015 and
2014, respectively. Other revenue for the years ended December 31, 2015 and 2014 was primarily
comprised of payments received from a third party for the extraction of iodine from our produced salt
water.
62
Oil, Natural Gas and NGL Production
PRODUCTION DATA:
Oil (Bbls/d)
Mississippian Lime . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . .
Natural gas liquids (Bbls/d)
Mississippian Lime . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . .
Natural gas (Mcf/d)
Mississippian Lime . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . .
Combined (Boe/d)
Mississippian Lime . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . .
Gulf Coast . . . . . . . . . . . . . . . . . . .
Crude Oil Production
Successor Period
Successor
Predecessor
For the Period
October 21, 2016
Through
For the Period
January 1, 2016
Through
Years Ended December 31,
December 31, 2016 October 20, 2016
2015
% Change
2014
6,048
1,508
—
4,843
1,118
—
58,816
9,903
—
20,694
4,277
—
8,156
1,927
—
5,326
1,247
—
68,107
10,856
—
24,833
4,983
—
10,194
2,680
260
5,307
1,388
81
64,688
12,921
208
26,282
6,222
376
21.2% 8,411
(33.2)% 4,014
(84.4)% 1,669
19.6% 4,437
(21.4)% 1,766
(80.7)% 419
24.3% 52,024
(13.5)% 14,930
(86.8)% 1,574
22.1% 21,518
(24.8)% 8,269
(84.0)% 2,350
For the Successor Period, our oil volumes sold averaged 7,556 Bbls/d, comprised of 6,048 Bbls/d
from our Mississippian Lime assets and 1,508 Bbls/d from our Anadarko Basin assets.
Predecessor Period
For the Predecessor Period, our oil volumes sold averaged 10,083 Bbls/d, comprised of 8,156 Bbls/d
from our Mississippian Lime assets and 1,927 Bbls/d from our Anadarko Basin assets.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
The decrease in oil volumes sold was due to a decrease of 1,409 Bbls/d of production volumes
from the Gulf Coast due to the sale of our remaining producing properties in Louisiana in April of
2015, as well as a decrease of 1,334 Bbls/d in production volumes from our Anadarko Basin area
attributable to natural production declines as we ran no drilling rigs during the year ended
December 31, 2015 due to the decline in commodity prices. These decreases were partially offset by an
increase in Mississippian Lime production of 1,783 Bbls/d due to increased drilling activity.
NGL Production
Successor Period
For the Successor Period, our NGLs volumes sold were 5,961 Bbls/d, comprised of 4,843 Bbls/d
from our Mississippian Lime assets and 1,118 Bbls/d from our Anadarko Basin assets.
63
Predecessor Period
For the Predecessor Period, our NGLs volumes sold were 6,573 Bbls/d, comprised of 5,326 Bbls/d
from our Mississippian Lime assets and 1,247 Bbls/d from our Anadarko Basin assets.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
The increase in NGLs volumes sold was attributable to an increase of 870 Bbls/d of production
volumes from our Mississippian Lime assets, partially offset by decreases in Anadarko Basin production
of 378 Bbls/d and Gulf Coast production of 338 Bbls/d.
Natural Gas Production
Successor Period
For the Successor Period, our natural gas volumes sold were 68,719 Mcf/d, comprised of 58,816
Mcf/d from our Mississippian Lime assets and 9,903 Mcf/d from our Anadarko Basin assets.
Predecessor Period
For the Predecessor Period, our natural gas volumes sold were 78,963 Mcf/d, comprised of 68,107
Mcf/d from our Mississippian Lime operations and 10,856 Mcf/d from our Anadarko Basin assets.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
The increase in natural gas volumes sold was attributable to an increase of 12,664 Mcf/d of
production volumes from our Mississippian Lime assets, partially offset by decreases of 2,009 Mcf/d in
production from our Anadarko Basin assets and 1,366 Mcf/d from our Gulf Coast assets.
Expenses
Successor
Predecessor
Successor
Predecessor
For the Period
October 21, 2016
Through
For the Period
January 1, 2016
Through
Years Ended
December 31,
For the Period
October 21, 2016
Through
For the Period
January 1, 2016
Through
Years Ended
December 31,
December 31, 2016 October 20, 2016
2015
2014
December 31, 2016 October 20, 2016
2015
2014
(in thousands)
(in thousands)
(per Boe)
(per Boe)
EXPENSES:
Lease operating and workover . $
Gathering and transportation .
.
Severance and other taxes .
Asset retirement accretion .
.
Depreciation, depletion, and
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
properties .
amortization .
.
Impairment of oil and gas
.
.
.
General and administrative .
Acquisition and transaction
.
.
.
Debt restructuring costs and
.
.
advisory fees
.
.
Other .
costs .
. . .
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
15,324 $
3,194
1,286
210
12,974
—
4,864
—
—
—
52,803 $
14,362
5,210
1,414
81,473 $ 79,598 $
15,546
8,605
1,610
13,404
24,266
1,706
62,302
198,643
269,935
232,108
22,362
1,625,776
38,703
86,471
48,733
—
330
4,129
7,590
—
36,141
2,121
—
5,108
8.52 $
1.78
0.72
0.12
7.22
—
2.71
—
—
—
6.02 $
1.64
0.59
0.16
6.79 $ 6.79
1.14
1.30
2.07
0.72
0.15
0.13
7.11
16.55
23.01
26.48
2.55
135.47
3.22
7.37
4.15
—
0.03
0.35
0.87
—
3.01
0.18
—
0.44
Total expenses
.
.
.
.
.
.
.
. $
37,852 $
398,151 $2,008,948 $533,350 $
21.07 $
45.42 $167.40 $45.47
Lease Operating and Workover
Lease operating expenses represent costs incurred to bring oil and gas out of the ground and to
the market, together with the daily costs incurred to maintain our producing properties. Such costs also
include natural gas treating expenses and the handling and disposal of produced water as well as
maintenance and repair expenses related to our oil and gas properties. Lease operating expenses
include both a portion of costs that are fixed in nature, such as infrastructure costs and compressor
64
rental costs, as well as variable costs resulting from additional wells and production, such as chemicals
and electricity. As production increases, our average lease operating expense per barrel of oil
equivalent is typically reduced because fixed costs do not increase proportionately with production.
Workover expense includes major remedial operations on a completed well to restore, maintain, or
improve a well’s production and is closely correlated to the levels of workover activity. Because
workover projects are pursued on an as needed basis and are not regularly scheduled, workover
expense is not necessarily comparable from period to period.
Successor Period
For the Successor Period, our lease operating and workover expenses were $15.3 million at a cost
of $8.52 per Boe. Lease operating and workover expenses for the Successor Period were impacted by
weather disruptions, which lowered production and increased costs during the period.
Predecessor Period
For the Predecessor Period, our lease operating and workover expenses were $52.8 million at a
cost of $6.02 per Boe.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
The decrease in lease operating expense is primarily related to the Dequincy Divestiture in the
second quarter of 2015. The increase in workover expenses during the year is due to increased
production optimization projects, primarily in the Anadarko Basin. Total lease operating and workover
expenses increased for the year ended December 31, 2015, while the per unit amount remained
unchanged at $6.79 per Boe.
Gathering and Transportation
Gathering and transportation costs are incurred for the movement of natural gas to the contractual
delivery point. For the Successor Period, Predecessor Period and the years ended December 31, 2015
and 2014, these costs relate to the amended gas transportation, gathering and processing contract which
commenced during the third quarter of 2013 in our Mississippian Lime assets.
Successor Period
For the Successor Period, our gathering and transportation expenses were $3.2 million at a cost of
$1.78 per Boe.
Predecessor Period
For the Predecessor Period, our gathering and transportation expenses were $14.4 million at a cost
of $1.64 per Boe.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
The increase in gathering and transportation costs was primarily attributable to a 13.6% increase in
natural gas production volumes for the year ended December 31, 2015.
Severance and Other Taxes
Severance taxes are paid on produced oil and gas based on a percentage of revenues from
products sold at market prices or at fixed rates established by federal, state, or local taxing authorities.
We attempt to take full advantage of all credits and exemptions in our various taxing jurisdictions. In
general, the severance taxes we pay correlate to the changes in oil and gas revenues. Ad valorem taxes
65
are property taxes assessed based on the value of property and are also included in this expense
category.
Successor
For the Period
October 21, 2016
Through
December 31, 2016
(in thousands)
Predecessor
For the Period
January 1, 2016
Through
October 20, 2016
Years Ended
December 31,
2015
2014
(in thousands)
Total oil, natural gas, and natural gas liquids
sales . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Severance taxes . . . . . . . . . . . . . . . . . . . . . .
Ad valorem and other taxes . . . . . . . . . . . . .
Severance and other taxes . . . . . . . . . . . . . .
Severance taxes as a percentage of sales . . . .
Severance and other taxes as a percentage of
sales . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
Successor Period
47,575
1,093
193
1,286
$
$
2.3%
2.7%
188,419
$322,708
$653,630
4,058
1,152
5,754
2,851
17,723
6,543
5,210
$
8,605
$ 24,266
2.2%
2.8%
1.8%
2.7%
2.7%
3.7%
For the Successor Period, our severance and other tax expenses were $1.3 million or 2.7% of sales.
Severance tax was $1.1 million or 2.3% of sales during the Successor Period.
Predecessor Period
For the Predecessor Period, our severance and other tax expenses were $5.2 million or 2.8% of
sales. Severance tax was $4.1 million or 2.2% of sales during the Predecessor Period.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
The decrease in severance taxes was primarily due to lower realized pricing in the 2015 period and
the sale of our Louisiana (or Gulf Coast) properties which had higher effective severance tax rates than
our Mississippian Lime and Anadarko Basin properties. Ad valorem taxes decreased due to a
significant decrease in the value of our proved oil and gas reserves from 2014 to 2015.
Depreciation, Depletion and Amortization (‘‘DD&A’’)
Under the full cost accounting method, we capitalize costs within a cost center and systematically
expense those costs on a unit of production basis based on proved oil and natural gas reserve
quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than
the cost of investments in unproved properties which remain to be evaluated, less accumulated
amortization; (ii) estimated future expenditures to be incurred in developing proved reserves; and
(iii) estimated dismantlement and abandonment costs, net of any associated salvage value.
Successor Period
For the Successor Period, our DD&A expenses were $13.0 million at a cost of $7.22 per Boe.
Predecessor Period
For the Predecessor Period, our DD&A expenses were $62.3 million at a cost of $7.11 per Boe.
66
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
The decrease in DD&A expense is primarily attributable to lower DD&A rates, $16.55 per Boe for
the year ended December 31, 2015 as compared to $23.01 per Boe for the year ended December 31,
2014, primarily due to ceiling test impairments recognized during the 2015 period.
Impairment of Oil and Gas Properties
As we account for our oil and gas properties under the full cost method, we are required to
perform a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book
value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of
accumulated DD&A and the related deferred income taxes, may not exceed this ‘‘ceiling.’’ The ceiling
limitation is equal to the sum of: (i) the present value of estimated future net revenues from the
projected production of proved oil and gas reserves, excluding future cash outflows associated with
settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and
natural gas sales price we received as of the first trading day of each month over the preceding twelve
months (such average price is held constant throughout the life of the properties) and a discount factor
of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized;
(iii) the lower of cost or estimated fair value of unproved properties included in the costs being
amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is
charged to impairment expense in the accompanying consolidated statements of operations.
Successor Period
For the Successor Period, we did not incur any impairments of oil and gas properties.
Predecessor Period
For the Predecessor Period, our impairment of oil and gas properties was $232.1 million. The
impairment expense recognized in the Predecessor Period was primarily due to a decrease in the PV-10
value of our proven oil and natural gas reserves as a result of continued low commodity prices, which
are a significant input into the calculation of the discounted future cash flows associated with our
proved oil and gas reserves.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
For the year ended December 31, 2015, our impairment of oil and gas properties was $1.6 billion.
The impairment expense for the 2015 period was primarily due to a decrease in the PV-10 value of our
proven oil and natural gas reserves as a result of continued low commodity prices, which are a
significant input into the calculation of the discounted future cash flows associated with our proved oil
and gas reserves.
General and Administrative (‘‘G&A’’)
G&A expense consists of, among other items, overhead, including payroll and benefits for our
corporate staff, non-cash charges for share-based compensation, costs of maintaining our headquarters,
franchise taxes, audit and other professional fees, legal compliance, reporting expenses, investor
relations, director and officer liability insurance costs, and director compensation.
Successor Period
For the Successor Period, our G&A expense was $4.9 million at a cost of $2.71 per Boe. G&A for
the Successor Period includes primarily professional fees and credits to previously incurred professional
fees for reorganization type items, resulting in credit of $1.1 million, and non-cash stock based
compensation expense for awards issued pursuant to the 2016 LTIP of $2.9 million.
67
Predecessor Period
For the Predecessor Period, our G&A expense was $22.4 million at a cost of $2.55 per Boe. G&A
for the Predecessor Period includes $1.3 million of accelerated expense associated with cancelled stock
compensation awards and $1.6 million in severance costs.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
The $10.0 million decrease period over period is primarily related to a $4.8 million reduction in
employee costs due to reduced headcount in 2015, a $4.4 million increase in capitalized overhead costs
and cost recoveries, as well as $0.6 million less in professional fees.
Acquisition and Transaction Costs
Acquisition and transaction costs are costs we have incurred as a result of acquisitions or as a
result of asset disposition transactions and include finders’ fees, advisory, legal, accounting, valuation
and other professional and consulting fees and other acquisition or disposition related general and
administrative costs. Acquisition and transaction related costs are expensed as incurred and as services
are received.
Successor Period
For the Successor Period, we did not incur any acquisition and transaction costs.
Predecessor Period
For the Predecessor Period, we did not incur any acquisition and transaction costs.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
For the year ended December 31, 2015, acquisition and transaction costs are related to our
expenses incurred with the Dequincy Divestiture. For the year ended December 31, 2014, acquisition
and transaction costs primarily represent our expenses related to the Pine Prairie Disposition.
Debt Restructuring Costs and Advisory Fees
Debt restructuring costs and advisory fees include costs incurred for legal, financing and advisor
costs associated with specific transactions, such as troubled debt restructuring, or costs incurred prior to
the Petition Date.
Successor Period
For the Successor Period, we did not incur any debt restructuring costs and advisory fees.
Predecessor Period
For the Predecessor Period, we incurred $7.6 million of debt restructuring costs and advisory fees
related to our bankruptcy and restructuring process prior to the Petition Date.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
During the 2015 period, we engaged various advisors to assist us in analyzing options to improve
our financial flexibility and provide additional long-term liquidity. For the year ended December 31,
2015, we incurred approximately $36.1 million in fees associated with these advisors as well as issuance
costs associated with the Second Lien Notes offering and Third Lien Notes exchange.
68
Other
Other expense consists of, among other things, losses on disposal of, or market value adjustments
to, field equipment inventory, penalties on early termination of drilling contracts and other
miscellaneous expense items.
Successor Period
For the Successor Period, we did not incur any other expense.
Predecessor Period
For the Predecessor Period, we did not incur any other expense.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
For the year ended December 31, 2015, other expenses relate to the loss on disposal of, or market
value adjustments to, field equipment inventory deemed no longer useful to current operations. For the
year ended December 31, 2014, other expenses relate to the loss on disposal of, or market value
adjustments to, field equipment inventory deemed no longer useful to current operations as well as
penalty fees associated with the early termination of a drilling rig contract.
Other Income/Expense
Successor
For the Period
October 21,
2016
Through
December 31,
2016
(in thousands)
For the Period
January 1,
2016
Through
October 20,
2016
Predecessor
Years Ended
December 31,
2015
2014
(in thousands)
OTHER INCOME (EXPENSE)
Interest income . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
81
$
115
$
39
Interest expense . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred financing costs . . . . . .
Amortization of deferred gain . . . . . . . . . . . . .
Capitalized interest . . . . . . . . . . . . . . . . . . . . .
Interest expense—net of amounts capitalized
(Predecessor Period excludes interest expense
of $89.5 million on senior and secured notes) .
Reorganization items . . . . . . . . . . . . . . . . . .
(1,409)
(62)
—
728
(70,019)
(4,587)
8,246
—
(182,955)
—
14,948
4,859
(149,962)
—
—
12,414
(743)
—
(66,360)
1,594,281
(163,148)
—
(137,548)
—
Total other income (expense) . . . . . . . . . . . .
$
(743) $ 1,528,002
$(163,033) $(137,509)
Interest Expense
Prior to the Effective Date, we had substantial long-term debt in the form of our 2020 Senior
Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes. Additionally, we financed a
portion of our working capital requirements and capital expenditures with borrowings under our RBL.
Included within interest expense for periods prior the Successor Period is the amortization of the
related deferred financing costs, net of any amounts capitalized to unproved properties, and
amortization of the deferred gain recognized on the restructuring of our debt, which occurred in the
second quarter of 2015 and was being recognized as a reduction to interest expense using the effective
interest method.
69
Successor Period
For the Successor Period, we incurred $1.4 million of interest expense related to our Exit Facility
which bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. At
December 31, 2016, the weighted average interest rate was 5.50%. We also capitalized $0.7 million of
interest expense to our unevaluated oil and gas properties during the period.
Predecessor Period
For the Predecessor Period, we incurred $70.0 million of interest expense. During the Predecessor
Period, we reclassified our Senior Notes, Second Lien Notes and Third Lien Notes to liabilities subject
to compromise in connection with the Chapter 11 Cases. As such, we ceased recognizing interest
expense for all debt except amounts outstanding under the RBL beginning at the Petition Date.
Contractual interest not reflected in the consolidated statements of operations was approximately
$89.5 million, which represents interest expense incurred subsequent to the Petition Date. No interest
expense was capitalized during the period due to the transfer of all balances related to unevaluated
property to the full cost pool at December 31, 2015.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
The increase in interest expense was primarily due to the issuance of the Second Lien Notes on
May 21, 2015 and Third Lien Notes on May 21, 2015 and June 2, 2015. The Second Lien Notes bore
interest at 10.0% and a portion of the proceeds were used to repay outstanding borrowings under the
RBL. Additionally, the Third Lien Notes bore interest at 12.0% and were exchanged for a portion of
the 2020 Senior Notes and 2021 Senior Notes, which had stated interest rates of 10.75% and 9.25%,
respectively. Further, approximately $4.6 million in unamortized debt costs were impaired during the
2015 period as a result of the Seventh Amendment to the RBL. The increase in interest expense was
partially offset by $14.9 million in amortization of the deferred gain on forgiven debt related to the
Third Lien Notes exchange. For the years ended December 31, 2015 and 2014, approximately $4.9
million and $12.4 million, respectively, in interest expense was capitalized to oil and gas properties.
Capitalized interest was lower due to a decrease in the balance of our unevaluated property during the
2015 period. The remaining value of unevaluated properties was transferred to the full cost pool as of
December 31, 2015.
Reorganization Items, Net
Reorganization items, net, represent the direct and incremental costs of being in bankruptcy from
the Petition Date through the Effective Date, and include such items as professional fees, gains from
pre-petition liability claim adjustments and losses related to terminated contracts that are probable and
can be estimated.
Successor Period
For the Successor Period, we did not recognize any reorganization items.
Predecessor Period
For the Predecessor Period, we recognized $1.6 billion of reorganization income related to our
emergence from bankruptcy. Reorganization items include a $1.3 billion gain on the settlement of
liabilities subject to compromise, $111.4 million of adjustments to unamortized gains on troubled debt
restructuring related to the issuance of the Second Lien Notes and the Third Lien Notes, $23.4 million
of adjustments to unamortized debt issuance costs, $38.8 million of professional fees incurred and
$274.2 million of fresh start adjustments and other reorganization items.
70
Provision for Income Taxes
Successor Period
For the Successor Period, we had no provision for income taxes due to the change in our valuation
allowance recorded against our net deferred tax assets.
Predecessor Period
For the Predecessor Period, we had no provision for income taxes due to the change in our
valuation allowance recorded against our net deferred tax assets.
Year Ended December 31, 2015 as Compared to the Year Ended December 31, 2014
Our income tax benefit was $9.6 million for the year ended December 31, 2015 and represents an
application of our estimated effective tax rate (including state income taxes) for the year ended
December 31, 2015 of approximately 0.5% to the pre-tax loss incurred throughout the year. The
significant reason for the change from an income tax expense to a benefit during the year ended
December 31, 2015 was the change in unrealized derivative losses of $126.7 million.
Capital Resources, Uses and Liquidity
Overview
Our decisions regarding capital structure, hedging and drilling are based upon many factors,
including anticipated future commodity pricing, expected economic conditions and recoverable reserves.
The unexpected substantial decrease in oil and gas prices that began in the second half of 2014 and
continued throughout 2015 and 2016 resulted in materially lower operating cash flows than we had
anticipated. In addition, all of our hedging contracts expired during 2015, and as a result, we did not
receive any cash derivative settlements during the Successor Period or Predecessor Period, which also
negatively impacted cash provided by operations for those periods as compared to our historical
operating cash flows. As a result of these factors, our debt service requirements became unsustainable
and we filed for a reorganization under Chapter 11 of the Bankruptcy Code on the Petition Date. On
the Effective Date, we satisfied the conditions to effectiveness set forth in the Confirmation Order and
in the Plan. As a result, our Plan became effective in accordance with its terms and we emerged from
the Chapter 11 Cases at that time. For additional information, please see ‘‘—Note 2. Emergence from
Voluntary Reorganization under Chapter 11 Proceedings’’ in the Notes to the Consolidated Financial
Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
On the Effective Date, $1.8 billion of debt was extinguished in accordance with the Plan, the
Second Lien Notes were exchanged for a cash payment of $60.0 million and 96.25% of our reorganized
equity in the form of common stock, and the Third Lien Notes and Senior Notes were exchanged for a
combination of our reorganized equity in the form of common stock and warrants to acquire additional
common shares of the reorganized equity and we entered into an Exit Facility providing up to
$170.0 million of credit. Additionally, we paid down $81.3 million owed under the RBL as well as an
additional payment of $40.0 million to lenders under our Exit Facility. As a result of our restructuring,
we estimate cash paid for interest will decrease from an average of approximately $173.7 million per
year to approximately $7.0 million per year, a cash interest savings of approximately $166.7 million per
year.
71
The following table provides adjustments that reflect the consummation of transactions
contemplated by the Plan, as of the Effective Date (excluding the Exit Facility):
As of
October 21, 2016
Predecessor
Reorganization October 21, 2016
Adjustments
Successor
As of
(in thousands)
Unsecured Notes:
2020 Senior Notes . . . . . . . . . . . . .
2021 Senior Notes . . . . . . . . . . . . .
Total Unsecured Notes . . . . . . . .
Secured Notes:
Second Lien Term Loan . . . . . . . . .
Third Lien Term Loan . . . . . . . . . .
Total Secured Notes . . . . . . . . . .
Total Debt (excluding Exit Facility) . .
$
$
$
$
$
293,625
347,652
641,277
625,000
529,653
$
$
$
(293,625) $
(347,652)
(641,277) $
(625,000) $
(529,653)
1,154,653
$ (1,154,653) $
1,795,930
$ (1,795,930) $
—
—
—
—
—
—
—
Historically, our primary sources of liquidity have been our operating cash flows, proceeds from
divestitures, cash on hand and cash available from borrowings under the Exit Facility. We anticipate our
operating cash flows and cash on hand will be our primary sources of liquidity subsequent to the
Effective Date, although we may seek to supplement our liquidity through divestitures, additional
borrowings or debt or equity securities offerings as circumstances and market conditions dictate. We
believe the combination of these sources of liquidity will be adequate to fund anticipated capital
expenditures, service our existing debt and remain compliant with all other contractual commitments.
Our cash flows from operations are impacted by various factors, the most significant of which is
the market pricing for oil, natural gas and NGLs. The pricing for these commodities is volatile, and the
factors that impact such market pricing are global and therefore outside of our control. As a result, it is
not possible for us to precisely predict our future cash flows from operating revenues due to these
market forces.
We have historically utilized derivatives to alleviate some of the volatility in market pricing. While
we did not utilize any derivatives throughout 2016, we did enter into various derivatives subsequent to
December 31, 2016, which are summarized in ‘‘—Note 6. Risk Management and Derivatives
Instruments’’ in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this
Annual Report on Form 10-K.
Our Capital Requirements
The following table summarizes factors affecting our liquidity (in thousands):
Successor
Predecessor
December 31,
2016
December 31,
2015
December 31,
2014
$
76,838
$
81,093
$
11,557
67,637
(1,838,758)
21,649
67,637
128,059
—
52,186
21,649
— 1,706,532
88,361
249,159
Cash and cash equivalents . . . . . . . . . . . . .
Net working capital, including debt classified
as current . . . . . . . . . . . . . . . . . . . . . . . .
Net working capital, excluding debt
classified as current . . . . . . . . . . . . . . . . .
Total long-term debt . . . . . . . . . . . . . . . . . .
Available borrowing capacity . . . . . . . . . . . .
72
At December 31, 2016, our liquidity was $76.8 million, composed entirely of our cash and cash
equivalents. During the Successor Period and the Predecessor Period, we incurred operational capital
expenditures of $16.8 million and $123.6 million, respectively, which consisted primarily of the following
(in thousands):
Successor
Predecessor
For the Period
October 21,
2016
through
December 31,
2016
For the Period
January 1,
2016
through
October 20,
2016
Drilling and completion activities . . . . . . . . . . . . . . . . .
Acquisition of acreage and seismic data . . . . . . . . . . . . .
$
Operational capital expenditures incurred . . . . . . . . . . .
Capitalized G&A, Office, ARO and Other . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Capitalized interest
$
16,100
702
16,802
1,608
728
116,764
6,869
123,633
4,904
—
Total capital expenditures incurred . . . . . . . . . . . . . .
$
19,138
$
128,537
Operational capital expenditures were incurred in the following areas for the Successor Period and
Predecessor Period (in thousands):
Mississippian Lime . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Anadarko Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operational capital expenditures incurred . . . . . . . . .
Successor
Predecessor
For the Period
October 21,
2016
through
December 31,
2016
For the Period
January 1,
2016
through
October 20,
2016
$
$
16,526
276
16,802
$
$
122,329
1,304
123,633
As of December 31, 2016, we had one drilling rig in operation in the Mississippian Lime. Subject
to the terms of our Exit Facility, we currently anticipate operating one rig in the Mississippian Lime
and investing between $90.0 million and $100.0 million of capital for exploration, development and
lease and seismic acquisition during the year ended December 31, 2017. We expect cash generated by
operations and cash on hand to be sufficient to fully fund our expected capital requirements.
Significant Sources of Capital
Exit Facility
At December 31, 2016, in addition to cash on hand of $76.8 million, we maintained the Exit
Facility. The Exit Facility has a current borrowing base of $170.0 million and no borrowing base
redeterminations are to occur until April 2018 (provided certain conditions are met) with semiannual
borrowing base redeterminations each year on April 1 and October 1 thereafter. Until April 2018,
unless the borrowing base is redetermined earlier, the amount available to be drawn under the Exit
Facility is reduced by $40.0 million, and thereafter, we must maintain liquidity (as defined therein)
equal to at least 20.0% of the effective borrowing base. At December 31, 2016, we had $128.1 million
drawn on the Exit Facility and outstanding letters of credit obligations totaling $1.9 million. As a result,
at December 31, 2016 we had no amount of availability on the Exit Facility.
The Exit Facility matures on September 30, 2020 and borrowings thereunder are secured by
(i) first-priority mortgages on at least 95% of the our oil and gas properties, (ii) all other presently
73
owned or after-acquired property (including but not limited to as-extracted collateral, accounts
receivable, inventory, equipment, general intangibles, investment property, intellectual property, real
property and the proceeds of the foregoing) and (iii) a perfected pledge on all equity interests. The
Exit Facility bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. At
December 31, 2016, the weighted average interest rate was 5.50%.
In addition to interest expense, the Exit Facility requires the payment of a commitment fee each
quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily
amount by which the borrowing base exceeds the outstanding borrowings during each quarter.
Debt Covenants
In addition to the aforementioned liquidity covenant, the Exit Facility also contains various other
financial covenants, including an EBITDA to interest expense coverage ratio limitation of 3.00:1.00, a
ratio limitation of Total Net Indebtedness (as defined in the Exit Facility) to EBITDA of not more than
2.25:1.00 through April 1, 2018 and not more than 3.00:1.00 thereafter, and a capital expenditure
limitation of $50.0 million for the 6 months ended December 31, 2016, $81.0 million for the year ended
December 31, 2017, $85.0 million for the year ended December 31, 2018 and $78.0 million for the year
ended December 31, 2019. The Exit Facility is also subject to a variety of other terms and conditions
including conditions precedent to funding, restrictions on the payment of dividends and various other
covenants and representations and warranties. As of December 31, 2016, we were in compliance with
our debt covenants.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our consolidated cash flows from operating, investing and
financing activities for the periods presented. For information regarding the individual components of
our cash flow amounts, please refer to the Consolidated Statements of Cash Flows included under
Item 15 of this Annual Report.
Our operating cash flows are sensitive to a number of variables, the most significant of which is
the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure
capacity to reach markets and other variable factors significantly impact the prices of these
commodities. These factors are beyond our control and are difficult to predict. For additional
information on the impact of changing prices on our financial position, see ‘‘Item 7A.—Quantitative
and Qualitative Disclosures about Market Risk.’’
The following information highlights the significant period-to-period variances in our cash flow
amounts (in thousands):
Successor
Predecessor
For the Period
October 21, 2016 through
December 31, 2016
For the Period
January 1, 2016 through
October 20, 2016
For the Years Ended
December 31,
2015
2014
Net cash provided by operating
activities . . . . . . . . . . . . . . . . .
$
23,644
$
61,997
$ 213,383
$ 351,544
Net cash used in investing
activities . . . . . . . . . . . . . . . . .
Net cash provided by financing
activities . . . . . . . . . . . . . . . . .
Net change in cash . . . . . . . . . . .
$
(23,346)
(133,307)
(294,556)
(404,264)
—
298
$
66,757
150,709
31,114
(4,553) $ 69,536
$ (21,606)
74
Cash flows provided by operating activities
Net cash provided by operating activities was $23.6 million, $62.0 million, $213.4 million and
$351.5 million for the Successor Period, Predecessor Period and the years ended December 31, 2015
and 2014, respectively.
The decrease in net cash provided by operating activities for the year ended December 31, 2015
compared to the year ended December 31, 2014 is primarily the result of a decrease in our oil and gas
revenues of $330.9 million attributable to lower commodity prices, partially offset by increased
settlements of derivatives of $186.0 million.
Cash flows used in investing activities
We had net cash used in investing activities of $23.3 million, $133.3 million, $294.6 million and
$404.3 million for the Successor Period, Predecessor Period and the years ended December 31, 2015
and 2014, respectively. Net cash used in investing activities for the Successor Period and Predecessor
Period represents cash invested in property and equipment.
The decrease in net cash used in investing activities for the year ended December 31, 2015 as
compared to the year ended December 31, 2014 was due to a reduced drilling program in the period as
a result of depressed commodity prices. During the year ended December 31, 2015, $336.9 million was
spent on our drilling program, partially offset by $42.4 million in proceeds received from the Dequincy
Divestiture. During the year ended December 31, 2014, $556.4 million was spent on our drilling
program, partially offset by $147.7 million in proceeds received for the Pine Prairie Disposition,
$3.0 million in proceeds received related to the Exploration Agreement with PetroQuest (discussed
further in ‘‘—Note 8. Acquisition and Divestitures of Oil and Gas Properties’’ in the Notes to the
Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K)
and $1.4 million in other asset sales.
Cash flows provided by financing activities
Net cash provided by financing activities was $66.8 million, $150.7 million and $31.1 million for the
Predecessor Period and the years ended December 31, 2015 and 2014, respectively. Net cash provided
by financing activities for the Predecessor Period primarily represents borrowings from the RBL of
$249.4 million offset partially by repayments of the RBL of $121.3 million and repayments of the
Second Lien Notes of $60.0 million.
The increase in net cash provided by financing activities for the year ended December 31, 2015 as
compared to the year ended December 31, 2014 was driven by the issuance of the Second Lien Notes
for proceeds of $625.0 million and borrowings from the RBL of $33.0 million. These proceeds were
partially offset by repayments on the RBL of $468.2 million and $34.4 million paid for restructuring
transaction costs. For the year ended December 31, 2014, we had draws on the revolver of
$165.0 million and repayments (using a portion of the proceeds from the Pine Prairie Disposition) of
$131.0 million.
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Other Items
Obligations and commitments
We have the following contractual obligations and commitments as of December 31, 2016 (in
thousands):
Reserves based revolving credit facility(1) . . . . .
Non-cancellable office lease commitments(2) . . .
Asset retirement obligations(3) . . . . . . . . . . . . .
Payments Due by Period
Total
$128,059
6,631
14,200
Less than
1 year
1 - 3 years
4 - 5 years
$ — $
642
—
— $128,059
1,392
—
1,997
—
More than
5 years
$
—
2,600
14,200
Net minimum commitments(4) . . . . . . . . . . . . .
$148,890
$
642
$ 1,997
$129,451
$ 16,800
(1) Amount excludes interest on our reserves based revolving credit facility as both the amount
borrowed and applicable interest rate is variable. As of December 31, 2016, we had drawn down
$128.1 million on our reserves based revolving credit facility and had $1.9 million of outstanding
letters of credit. See ‘‘—Note 10. Debt’’ in the Notes to the Consolidated Financial Statements set
forth in Part IV, Item 15 of this Annual Report on Form 10-K for further information.
(2) See ‘‘—Note 16. Commitments and Contingencies’’ in the Notes to the Consolidated Financial
Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K, for a description of
operating lease and other obligations.
(3) Amounts represent our estimate of future asset retirement obligations on a discounted basis.
Because these costs typically extend many years into the future, estimating these future costs
requires management to make estimates and judgments that are subject to future revisions based
upon numerous factors, including the rate of inflation, changing technology and the political and
regulatory environment. See ‘‘—Note 9. Asset Retirement Obligations’’ in the Notes to the
Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on
Form 10-K.
(4) Excluded from these amounts are any payments that may become necessary under our minimum
volume requirements in our gas purchase, gathering and processing contract in the Mississippian
Lime region; please see the Marketing and Major Purchasers discussion in the Business section of
this document.
Critical Accounting Policies and Estimates
We prepare our financial statements and the accompanying notes in conformity with US GAAP,
which requires our management to make estimates and assumptions about future events that affect the
reported amounts in our financial statements and the accompanying notes. We identify certain
accounting policies as critical based on, among other things, their impact on the portrayal of our
financial condition, results of operations or liquidity and the degree of difficulty, subjectivity and
complexity in their deployment. Critical accounting policies cover accounting matters that are inherently
uncertain because the future resolution of such matters is unknown. Our management routinely
discusses the development, selection and disclosure of each of the critical accounting policies. Following
is a discussion of our most critical accounting policies:
Fresh Start Accounting
Upon our emergence on the Effective Date, we adopted fresh start accounting as required by
US GAAP. We qualified for fresh start accounting because (i) the holders of existing voting shares of
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the pre-emergence debtor-in-possession received less than 50% of the voting shares of the
post-emergence successor entity and (ii) the reorganization value of our assets immediately prior to
confirmation was less than the post-petition liabilities and allowed claims. We applied fresh start
accounting as of the Effective Date. Adopting fresh start accounting results in a new reporting entity
for financial reporting purposes with no beginning retained earnings or deficit and all of our assets and
liabilities marked to fair value as of the Effective Date. As a result of the application of fresh start
accounting, as well as the effects of the implementation of the Plan, our consolidated financial
statements on or after the Effective Date are not comparable with our consolidated financial
statements prior to that date.
There are various assumptions we made in determining the fair values of our assets and liabilities
at the Effective Date. The most significant assumptions involve the estimated fair values of our oil and
gas properties. To determine the fair values of these properties, we prepared estimates of oil, natural
gas and NGL reserves as of the Effective Date. The engineering assumptions contained within this
reserves report were consistent with both (i) previous engineering assumptions made by us when
preparing reserve reports in prior years and (ii) assumptions promulgated by the SEC. These
assumptions include type curves and analogous reservoir characteristics determined utilizing electrical
logs, radioactivity logs, core analyses, geologic maps and available downhole and production data,
seismic data and well test data, to name a few. We then utilized an outside third-party expert to assist
us in the preparation of a valuation report utilizing assumptions consistent with a market participant.
This valuation report utilized the income approach in determining the fair value of our oil and gas
reserves, excluding possible reserves, for which the market approach was utilized. The income approach
involves the projection of cash flows a market participant would expect an asset or business to generate
over its remaining useful life. These projected cash flows from our oil and gas properties are adjusted
for risk based upon the reserves category before being further adjusted for estimates of various indirect
costs associated with the production of such reserves, such as general and administrative costs, income
taxes and the impact of inflation. These cash flows are projected on an annual basis for a discrete
period of time and then converted to their present value using a rate of return that captures the
relevant risk of achieving the projected cash flows, which is based upon an estimated required return of
capital for debt and equity for a market participant. Finally, the present value of the residual value, or
terminal value, is added to these discrete cash flows to arrive at the estimate of total value. The market
approach, which was utilized to value possible reserves, measures value through the use of prices,
market multiples and other relevant information involving identical or comparable assets or business
interests, which were largely determined based upon widely utilized industry sources and other relevant
data in the respective area.
Unproved properties generally represent the value of probable and possible reserves. Due to the
inherent nature of such reserves, probable reserve estimates are more imprecise than those of proved
reserves. In order to compensate for the inherent risk of estimating and valuing unproved reserves, the
discounted future net revenues of probable reserves are reduced by an appropriate risk-weighting factor
in each particular instance. Possible reserves were not valued utilizing a discounted cash flow approach,
but rather through the use of industry data and specific transactions utilizing the market approach.
Full Cost Method of Accounting and Proved Reserve Estimates
Proved oil and gas reserves are the estimated quantities of crude oil, NGLs and natural gas that
geological and engineering data demonstrates with reasonable certainty to be recoverable in future
years from known reservoirs under existing operating conditions and government regulations. Proved
undeveloped reserves include those 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. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly
offsetting development areas that are reasonably certain of production when drilled, or where reliable
77
technology provides reasonable certainty of economic producibility. Undrilled locations may be
classified as having undeveloped reserves only if a development plan has been adopted indicating that
they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.
Despite the inherent imprecision in these engineering estimates, our reserves are used throughout
our financial statements. For example, since we use the units-of-production method to amortize our oil
and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and
gas properties are also subject to a ceiling limitation based in part on the quantity of our proved
reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.
Our estimates of reserves were calculated using an unweighted arithmetic average of commodity
prices in effect on the first day of each month, held flat for the life of the production, except where
prices are defined by contractual arrangements.
Because the ceiling calculation dictates the use of prices that are not representative of future
prices and requires a 10% discount factor, the resulting value is not indicative of the true fair value of
the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period,
can be either higher or lower than our long-term price forecast, which is a more appropriate input for
estimating fair value. Therefore, oil and gas property write-downs that result from applying the full cost
ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the
underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the
ultimate value of the related reserves. Because of the volatile nature of oil and gas prices, it generally
is not possible to predict the timing or magnitude of full cost write-downs. However, based upon
commodity pricing for the first quarter of 2017 and industry expectations of future commodity prices,
we do not expect to recognize a full cost impairment in 2017.
Revenue Recognition
Our revenue recognition policy is significant because revenue is a key component of the results of
operations and of the forward-looking statements contained in the analysis of liquidity and capital
resources. We record revenue in the month our production is delivered to the purchaser, but payment
is generally received 30 to 90 days after the date of production. At the end of each month, we estimate
the amount of production that was delivered to the purchaser and the price that will be received. We
use our knowledge of our properties, their historical performance, the anticipated effect of weather
conditions during the month of production, NYMEX and local spot market prices and other factors as
the basis for these estimates. We record the variances between our estimates and the actual amounts
received in the month payment is received and such variances have historically not been significant.
Share-Based Compensation
Compensation expense associated with granted stock options and restricted stock units (excluding
restricted stock units containing a market condition) is determined based on our estimate of the fair
value of those awards at the initial grant date.
The fair value of restricted stock units is based on the fair value of an unrestricted share of
common stock at the grant date. We utilize the Black-Scholes-Merton option pricing model to measure
the fair value of stock options. Key inputs used in the option pricing model include the risk-free
interest rate, the expected volatility of the underlying stock and the expected life of the award.
Restricted stock units containing a market condition are treated as a liability award and the fair value is
based upon a Monte Carlo simulation utilizing assumptions for expected volatility, risk-free interest rate
and expected life that are updated quarterly until the award vests or expires. The key assumptions used
in measuring stock compensation expense for all awards are included in ‘‘—Note 12. Equity and Share-
Based Compensation’’ in the Notes to the Consolidated Financial Statements set forth in Part IV,
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Item 15 of this Annual Report on Form 10-K. We include share-based compensation expense in
‘‘General and administrative expense’’ in our consolidated statements of operations.
Asset Retirement Obligations
We have obligations to remove tangible equipment and facilities associated with our oil and
natural gas wells, and to restore land at the end of oil and natural gas production operations. The
removal and restoration obligations are associated with plugging and abandoning wells. Estimating the
future restoration and removal costs is difficult and requires us to make estimates and judgments
because most 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. Inherent
in the present value calculations are numerous assumptions and judgments including the ultimate
settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes
in the legal, regulatory, environmental and political environments.
The accounting guidance for asset retirement obligations requires that a liability for the present
value of estimated future retirement obligations be recorded in the period in which it is incurred and
the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The
discounted liability is then subsequently accreted to its new present value. The amount of liability
recorded for our asset retirement obligation is significantly impacted by our estimate of when the
liability will be settled because of the discounting effect that occurs to reflect the liability at the present
value of the future obligation. For example, at December 31, 2016, an increase of 5 years in the
estimated settlement date used for asset retirement purposes would impact the present value of our
asset retirement obligation by $(3.0) million, while a decrease of 5 years in the estimated settlement
date would have an impact of $3.6 million.
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of
federal, state, and provincial tax jurisdictions. We recognize current tax expense based on estimated
taxable income for the current period and the applicable statutory tax rates. We routinely assess
potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We
regularly assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is
more likely than not that some portion or all of the deferred tax assets will not be realized. The
ultimate realization of our deferred tax assets is dependent upon the generation of taxable income
during future periods. In light of a lack of positive evidence, we have recorded a full valuation
allowance against our net deferred tax assets of $160.8 million as of December 31, 2016.
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements as defined under Item 303(a)(4)(ii)
of Regulation S-K.
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (‘‘FASB’’) issued Accounting Standards
Update 2014-09, ‘‘Revenue from Contracts with Customers (Topic 606)’’ (‘‘ASU 2014-09’’). ASU 2014-09
provides guidance concerning the recognition and measurement of revenue from contracts with
customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial
79
statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 requires an entity to
perform the following steps:
Step 1—Identify the contract with a customer: A contract between two or more parties creates
enforceable rights and obligations. A contract that identifies the relevant parties and has been
approved by those parties, identifies the payment terms, has commercial substance and results in a
probable collection of future consideration meets the definition of ASU 2014-09.
Step 2—Identify the performance obligations in the contract: A performance obligation is
effectively a promise in a contract with a customer to transfer goods or services to the customer. If
an entity promises to transfer more than one good or service to the customer, each performance
obligation is accounted for separately if such performance obligations are distinct, as defined under
ASU 2014-09.
Step 3—Determine the transaction price: The amount of consideration an entity expects to be
entitled to as a result of performing services to a customer or transferring goods to a customer is
the transaction price. The transaction price takes into account variable consideration, the existence
of significant financing component, noncash consideration and the type of consideration payable to
the entity.
Step 4—Allocate the transaction price to the performance obligations in the contract: An entity
should allocate the transaction price to each performance obligation in an amount that represents
the amount of the entity expects to be entitled to for satisfying each performance obligation.
Step 5—Recognize revenue when, or as, the entity satisfies a performance obligation: An entity
recognizes revenue when, or as, it satisfies a performance obligation. A performance obligation can
be satisfied over time or at a point in time. ASU 2014-09 provides criteria for determining the
appropriate classification of each performance obligation.
Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue
recognition guidance in Topic 606, including ASU No. 2015-14, ‘‘Revenue from Contracts with Customers
(Topic 606): Deferral of the Effective Date’’ ASU No. 2016-08, ‘‘Revenue from Contracts with Customers
(Topic 606): Principal versus Agent Considerations’’, ASU No. 2016-10, ‘‘Revenue from Contracts with
Customers (Topic 606): Identifying Performance Obligations and Licensing’’, ASU No. 2016-12, ‘‘Revenue
from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients’’ and
ASU No. 2016-20, ‘‘Technical Corrections and Improvements to Topic 606, Revenue from Contracts with
Customers’’. ASU 2014-09 and the associated amendments mentioned above will be effective for us
beginning on January 1, 2018, including interim periods within that reporting period.
The standard permits the use of either the retrospective or cumulative effect transition method
and early adoption is permitted. Currently, we have identified the population of contracts and formed
an implementation team to determine our implementation timelines, discuss implementation challenges,
technical interpretations, industry-specific treatment of certain revenue contract types, and project
status. We plan to review contracts for each revenue stream identified within our business. Through this
process, we will determine and document the expected changes in revenue recognition upon adoption
of the revised guidance and then evaluate the potential information technology and internal control
changes that will be required for adoption based on the findings from our contract review process. We
will conduct our contract review process throughout 2017 and, as a result, areas of impact may be
identified. We cannot reasonably quantify the impact of adoption at this time. We expect to complete
our assessment of ASU 2014-09, including the transition method, in the latter half of 2017.
In August 2014, the FASB issued Accountings Standards Update 2014-15, ‘‘Presentation of Financial
Statements—Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity’s Ability to
Continue as a Going Concern’’ (‘‘ASU 2014-15’’). ASU 2014-15 provides guidance regarding
management’s responsibility to evaluate whether there are conditions or events, considered in the
80
aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within
one year after the date that the financial statements are issued. Certain disclosures are required should
substantial doubt exist about the entities ability to continue as a going concern. This evaluation is
performed each annual and interim reporting period to assess conditions or events within one year of
the date that the financial statements are issued. The new standard was adopted at December 31, 2016.
In February 2016, the FASB issued Accounting Standards Update 2016-02, ‘‘Leases (Topic 842)’’
(‘‘ASU 2016-02’’). ASU 2016-02 establishes a right-of-use (‘‘ROU’’) model that requires a lessee to
record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than
12 months. All leases create an asset and a liability for the lessee and therefore recognition of those
lease assets and lease liabilities is required by ASU 2016-02. When measuring lease assets and
liabilities, payments to be made in optional extension periods should be included if the lessee is
reasonably certain to exercise the option. Leases will be classified as either finance or operating, with
classification affecting the pattern of expense recognition in the income statement.
For finance leases, we will recognize a ROU asset and liability, initially measured at the present
value of the lease payments. Interest expense will be recognized on the lease liability separately from
the amortization of the ROU asset. We will recognize payments of principal on the lease liability within
financing activities in the consolidated statement of cash flows and payments of interest within
operating activities in the consolidated statement of cash flows. For operating leases, we will recognize
a ROU asset and liability, initially measured at the present value of the lease payments. We will
recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on
a generally straight-line basis and all cash payments will be recognized in operating activities within the
consolidate statement of cash flows.
The new standard is effective for fiscal years beginning after December 15, 2018, including interim
periods within those fiscal years. A modified retrospective transition approach is required for lessees
for capital and operating leases existing at, or entered into after, the beginning of the earliest
comparative period presented in the financial statements, with certain practical expedients available. We
are in the initial evaluation and planning stages for ASU 2016-02 and do not expect to move beyond
this stage until completion of our evaluation of ASU 2014-09, which is expected to occur in the latter
half of 2017.
In March 2016, the FASB issued ASU 2016-09, ‘‘Compensation—Stock Compensation (Topic 718)’’
(‘‘ASU 2016-09’’). ASU 2016-09 simplifies how certain aspects of share-based payments to employees
are recorded. ASU 2016-09 requires that entities recognize the income tax effects of awards in the
income statement when the awards vest or are settled, provides guidance on the classification of certain
aspects of share-based payments on the statement of cash flows, changes the threshold for awards to
qualify for equity classification, and allows an entity to make an accounting policy election to account
for forfeitures when they occur. The new standard is effective for us beginning on January 1, 2017. As
of December 31, 2016, we elected to early adopt the pronouncement.
In August 2016, the FASB issued ASU 2016-15, ‘‘Statement of Cash Flows—Classification of Certain
Cash Receipts and Cash Payments’’ (‘‘ASU 2016-15’’). ASU 2016-15 addresses eight specific cash flow
issues with the objective of reducing existing diversity of practice. The eight specific cash flow issues
contained within ASU 2016-15 are debt prepayment or debt extinguishment costs, settlement of
zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant
in relation to the effective interest rate of the borrowing, contingent consideration payments made after
a business combination, proceeds from the settlement of insurance claims, proceeds from the
settlement of corporate-owned life insurance policies, distributions received from equity method
investees, beneficial interests in securitization transactions and separately identifiable cash flows and
application of the predominance principle. ASU 2016-15 is effective for us for fiscal years beginning
after December 15, 2017, and interim periods within those fiscal years. We do not believe the adoption
of ASU 2016-15 will have a material impact on our cash flows.
81
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to a variety of market risks including commodity price risk, interest rate risk and
counterparty and customer risk. We address these risks through a program of risk management
including the use of derivative instruments.
The primary objective of the following information is to provide forward-looking quantitative and
qualitative information about our potential exposure to market risks. The disclosures are not meant to
be precise indicators of expected future losses or gains, but rather indicators of reasonably possible
losses or gains. This forward-looking information provides indicators of how we view and manage our
ongoing market risk exposures. All of our market risk sensitive instruments were entered into for
purposes other than speculative trading. These derivative instruments are discussed in ‘‘—Note 6. Risk
Management and Derivative Instruments’’ in the Notes to the Consolidated Financial Statements set
forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Commodity Price Exposure
We are exposed to market risk as the prices of oil, NGLs and natural gas fluctuate due to changes
in supply and demand. To partially reduce price risk caused by these market fluctuations, we have in
the past hedged and in the long-term, expect to hedge, a significant portion of our future production.
At December 31, 2016, we had no outstanding commodity derivative contracts, although we entered
into various derivatives subsequent to December 31, 2016 for a portion of our expected 2017
production and first quarter 2018 production. Please see ‘‘—Note 6. Risk Management and Derivative
Instruments’’ in the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this
Annual Report on Form 10-K for further information.
For derivative instruments outstanding, the credit standing of our counterparties is analyzed and
factored into the fair value amounts recognized on the balance sheet.
Assets and liabilities recorded at fair value in the balance sheets are categorized based upon the
level of judgment associated with the inputs used to measure their value. Our only financial assets and
liabilities that are measured at fair value on a recurring basis are the derivative instruments discussed
above. Our policy is to net derivative assets and liabilities where there is a legally enforceable master
netting agreement with the counterparty.
Interest Rate Risk
At December 31, 2016, we had indebtedness outstanding under our Exit Facility of $128.1 million,
which bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. Assuming the
Exit Facility is fully drawn, a one percent increase in interest rates would result in a $1.3 million
increase in annual interest cost, before capitalization.
At December 31, 2016, we did not have any interest rate derivatives in place and have not
historically utilized interest rate derivatives. In the future, we may utilize interest rate derivatives to
alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues.
Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall
leverage of the debt portfolio.
Counterparty and Customer Credit Risk
Joint interest receivables arise from billing entities that own partial interest in the wells we
operate. These entities participate in our wells primarily based on their ownership in leases on which
we wish to drill. We have limited ability to control participation in our wells. We are also subject to
credit risk due to concentration of our oil and natural gas receivables with several significant customers.
See ‘‘Business—Marketing and Major Purchasers’’ for further detail about our significant customers.
82
The inability or failure of our significant customers to meet their obligations to us or their insolvency
or liquidation may adversely affect our financial results. In addition, our future oil and natural gas
derivative arrangements may expose us to credit risk in the event of nonperformance by counterparties.
We evaluate the credit standing of our various counterparties as we deem appropriate under the
circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financial
information and, in the case of a customer with which we have receivables, their historical payment
record, the financial ability of the customer’s parent company to make payment if the customer cannot
and undertaking the due diligence necessary to determine credit terms and credit limits. Several of our
significant customers for oil and gas receivables have a credit rating below investment grade or do not
have rated debt securities. In these circumstances, we have considered the lack of investment grade
credit rating in addition to the other factors described above.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our Consolidated Financial Statements, together with the report of our independent registered
public accounting firm begin on page F-1 of this Annual Report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item
the information to be disclosed in our definitive proxy statement for our 2016 Annual Meeting of
Stockholders.
ITEM 9A. CONTROLS 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 management, including our principal executive officer and principal
financial officer, the effectiveness of the design and operation of our disclosure controls and procedures
(as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period
covered by this Annual Report. 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 principal
executive officer and principal 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 upon the evaluation, our principal executive officer
and principal financial officer have concluded that our disclosure controls and procedures were
effective at December 31, 2016 at the reasonable assurance level.
Management’s Annual Report on Internal Control over Financial Reporting
The management of the Company is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f).
Internal control over financial reporting is defined as a process designed by, or under the supervision
of, the issuer’s principal executive and principal financial officers, or persons performing similar
functions, and effected by the Company’s board of directors, management, and other personnel, to
provide reasonable assurance regarding reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles and
includes those policies and procedures which (a) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of the
Company, (b) provide reasonable assurance that transactions are recorded as necessary to permit
83
preparation of financial statements in accordance with generally accepted accounting principles, and
that receipts and expenditures are being made only in accordance with authorizations of management
and the board of directors, and (c) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of assets that could have a material effect on
the financial statements. A material weakness is a deficiency, or a combination of deficiencies, in
internal control over financial reporting such that there is a reasonable possibility that a material
misstatement of the annual or interim financial statements will not be prevented or detected on a
timely basis.
Under the supervision and with the participation of our management, including our principal
executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our
internal control over financial reporting based on the Internal Control Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of The Treadway Commission. Based on our
evaluation under the Internal Control Integrated Framework (2013), our management concluded that our
internal control over financial reporting was effective as of December 31, 2016.
Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting during the quarter ended
December 31, 2016 that have materially affected or are reasonably likely to materially affect the
Company’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
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PART III.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE
GOVERNANCE
Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item
the information to be disclosed in our definitive proxy statement for our 2016 Annual Meeting of
Stockholders.
ITEM 11. EXECUTIVE COMPENSATION
Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item
the information to be disclosed in our definitive proxy statement for our 2016 Annual Meeting of
Stockholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDERS
Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item
the information to be disclosed in our definitive proxy statement for our 2016 Annual Meeting of
Stockholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item
the information to be disclosed in our definitive proxy statement for our 2016 Annual Meeting of
Stockholders.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Pursuant to General Instructions G(3) to Form 10-K, we incorporate by reference into this Item
the information to be disclosed in our definitive proxy statement for our 2016 Annual Meeting of
Stockholders.
85
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART IV.
(a) The following documents are filed as a part of this Annual Report on Form 10-K or incorporated
herein by reference:
(1) Financial Statements:
See Item 8. Financial Statements and Supplementary Data.
(2) Financial Statement Schedules:
None.
(3) Exhibits:
The following documents are included as exhibits to this report:
2.1
3.1
3.2
4.01
4.02
10.01
10.02
10.03
First Amended Joint Chapter 11 Plan Of Reorganization of Midstates Petroleum
Company, Inc. and its Debtor Affiliate, dated September 28, 2016 (filed as Exhibit 2.1 to
the Company’s Current Report on Form 8-K filed on October 4, 2016, and incorporated
herein by reference).
Second Amended and Restated Certificate of Incorporation of Midstates Petroleum
Company, Inc. (filed as Exhibit 3.1 to the Company’s Registration Statement on
Form 8-A filed on October 21, 2016, and incorporated herein by reference).
Amended and Restated Bylaws of Midstates Petroleum Company, Inc. (filed as
Exhibit 3.2 to the Company’s Registration Statement on Form 8-A filed on October 21,
2016, and incorporated herein by reference).
Warrant Agreement, dated as of October 21, 2016 between Midstates Petroleum
Company, Inc. and American Stock Transfer & Trust Company, LLC (filed as Exhibit 4.1
to the Company’s Current Report on Form 8-K filed on October 27, 2016, and
incorporated herein by reference).
Warrant Agreement, dated as of October 21, 2016, between Midstates Petroleum
Company, Inc. and American Stock Transfer & Trust Company, LLC (filed as Exhibit 4.2
to the Company’s Current Report on Form 8-K filed on October 27, 2016, and
incorporated herein by reference).
Plan Support Agreement, dated as of April 30, 2016, by and among Midstates Petroleum
Company, Inc., Midstates Petroleum Company LLC and the supporting parties thereto
(filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 2,
2016, and incorporated herein by reference).
First Amendment to Plan Support Agreement, dated as of June 29, 2016, by and among
Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and the
supporting parties thereto (filed as Exhibit 10.1 to the Company’s Current Report on
Form 8-K filed on July 6, 2016, and incorporated herein by reference).
Second Amendment to Plan Support Agreement, dated as of August 31, 2016, by and
among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and the
supporting parties thereto. (filed as Exhibit 10.1 to the Company’s Current Report on
Form 8-K filed on September 7, 2016, and incorporated herein by reference).
86
10.04
10.05
10.06
10.7**
10.8**
10.9**
10.10
10.11
Registration Rights Agreement, dated October 21, 2016, between Midstates Petroleum
Company, Inc. and certain holders party thereto (filed as Exhibit 10.1 to the Company’s
Registration Statement on Form 8-A filed on October 21, 2016, and incorporated herein
by reference).
Midstates Petroleum Company, Inc. 2016 Long Term Incentive Plan (filed as Exhibit 10.1
to the Company’s Registration Statement on Form S-8 filed on October 24, 2016, and
incorporated herein by reference).
Senior Secured Credit Agreement, dated as of October 21, 2016, by and among
Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, as borrower,
SunTrust Bank, as administrative agent, and certain lenders party thereto (filed as
Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 27, 2016,
and incorporated herein by reference).
Employment Agreement of Frederic F. Brace, dated October 21, 2016 (filed as
Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on October 27, 2016,
and incorporated herein by reference).
Employment Agreement of Nelson M. Haight, dated October 21, 2016 (filed as
Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on October 27, 2016,
and incorporated herein by reference).
Employment Agreement of Mitchell G. Elkins, dated October 21, 2016 (filed as
Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on October 27, 2016,
and incorporated herein by reference).
Form of Midstates Petroleum Company, Inc. Director Restricted Stock Unit Agreement
(Annual Grant Agreement) (filed as Exhibit 10.1 to the Company’s Current Report on
Form 8-K filed on November 29, 2016, and incorporated herein by reference).
Form of Midstates Petroleum Company, Inc. Director Restricted Stock Unit Agreement
Pursuant to the 2016 Long Term Incentive Plan (filed as Exhibit 10.2 to the Company’s
Current Report on Form 8-K filed on November 29, 2016, and incorporated herein by
reference).
12.1(a)
Statement of Computation of Ratio of Earnings to Fixed Charges
21.1(a) List of subsidiaries of the Company.
23.1(a) Consent of Grant Thornton LLP
23.2(a) Consent of Deloitte & Touche LLP
23.3(a) Consent of Netherland, Sewell and Associates, Inc.—Independent Petroleum Engineers
23.4(a) Consent of Cawley, Gillespie & Associates, Inc.—Independent Petroleum Engineers
31.1(a)
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)
Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
99.1(a) Report of Cawley, Gillespie & Associates, Inc.
101.INS(a) XBRL Instance Document.
101.SCH(a) XBRL Schema Document.
87
101.CAL(a) XBRL Calculation Linkbase Document.
101.DEF(a) XBRL Definition Linkbase Document.
101.LAB(a) XBRL Labels Linkbase Document
101.PRE(a) XBRL Presentation Linkbase Document.
(a) Filed herewith
(b) Furnished herewith
** Management contract or compensatory plan or arrangement
ITEM 16. FORM 10-K SUMMARY
None.
88
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly
authorized.
SIGNATURES
Dated: March 30, 2017
MIDSTATES PETROLEUM COMPANY, INC.
/s/ FREDERIC F. BRACE
Frederic F. Brace
President and Chief Executive Officer
(Principal Executive Officer)
Dated: March 30, 2017
/s/ NELSON M. HAIGHT
Nelson M. Haight
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
89
Dated: March 30, 2017
KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Frederic F. Brace and Nelson M. Haight, each of whom may act without
joinder of the other, as their true and lawful attorneys-in-fact and agents, each with full power of
substitution and resubstitution, for such person and in his or her name, place and stead, in any and all
capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same,
with all exhibits thereto and other documents in connection therewith, with the Securities and
Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do
and perform each and every act and thing requisite and necessary to be done in and about the
premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and
confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do or cause to be
done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated.
Signatures
Title
Date
/s/ FREDERIC F. BRACE
Frederic F. Brace
/s/ NELSON M. HAIGHT
Nelson M. Haight
President and Chief Executive Officer
(Principal Executive Officer)
March 30, 2017
Executive Vice President and Chief
Financial Officer (Principal Financial
Officer)
March 30, 2017
/s/ RICHARD W. MCCULLOUGH
Richard W. McCullough
Vice President and Chief Accounting
Officer (Principal Accounting Officer)
March 30, 2017
/s/ ALAN J. CARR
Alan J. Carr
/s/ PATRICE R. DOUGLAS
Patrice R. Douglas
/s/ NEAL P. GOLDMAN
Neal P. Goldman
/s/ MICHAEL S. REDDIN
Michael S. Reddin
/s/ TODD R. SNYDER
Todd R. Snyder
/s/ BRUCE H. VINCENT
Bruce H. Vincent
Director (Chairman)
March 30, 2017
Director
Director
Director
Director
Director
90
March 30, 2017
March 30, 2017
March 30, 2017
March 30, 2017
March 30, 2017
MIDSTATES PETROLEUM COMPANY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firms . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated balance sheets as of December 31, 2016 (Successor Period) and 2015 (Predecessor
Period) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of operations for the periods October 21, 2016 through December 31,
2016 (Successor Period) and January 1, 2016 through October 20, 2016 (Predecessor Period)
and years ended December 31, 2015 and 2014 (Predecessor Period) . . . . . . . . . . . . . . . . . . . .
Consolidated statement of changes in stockholders’ equity (deficit) for the periods October 21,
2016 through December 31, 2016 (Successor Period) and January 1, 2016 through October 20,
2016 (Predecessor Period) and years ended December 31, 2015 and 2014 (Predecessor Period)
Page
F-2
F-4
F-5
F-6
Consolidated statements of cash flows for the periods October 21, 2016 through December 31,
2016 (Successor Period) and January 1, 2016 through October 20, 2016 (Predecessor Period)
F-7
and years ended December 31, 2015 and 2014 (Predecessor Period) . . . . . . . . . . . . . . . . . . . .
F-8
Notes to consolidated financial statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplemental oil and gas information (unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-52
Selected quarterly financial data (unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-58
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Midstates Petroleum Company, Inc.
We have audited the accompanying consolidated balance sheet of Midstates Petroleum Company, Inc. (a
Delaware corporation) and subsidiary (the ‘‘Company’’) as of December 31, 2016 (Successor), and the
related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for
the period from October 21, 2016 through December 31, 2016 (Successor) and the period from January 1,
2016 through October 20, 2016 (Predecessor). These financial statements are the responsibility of the
Company’s management. Our responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit 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 Company’s internal control over financial reporting. Our audit included
consideration of internal control over financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of
the Company’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 audit provides 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 Midstates Petroleum Company, Inc. and subsidiary as of December 31,
2016 (Successor) and the results of their operations and their cash flows for the period from October 21,
2016 through December 31, 2016 (Successor) and the period from January 1, 2016 through October 20,
2016 (Predecessor) in conformity with accounting principles generally accepted in the United States of
America.
As discussed in Note 2 to the consolidated financial statements, on September 28, 2016, the United States
Bankruptcy Court for the District of Texas entered into an order confirming the petition for
reorganization, which became effective on October 21, 2016. Accordingly, the accompanying consolidated
financial statements have been prepared in conformity with Accounting Standards Codification 852,
Reorganizations, for the Successor as a new entity with assets, liabilities and a capital structure having
carrying amounts not comparable with prior periods as described in Note 4.
/s/ GRANT THORNTON LLP
Kansas City, Missouri
March 30, 2017
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Midstates Petroleum Company, Inc.
Tulsa, Oklahoma
We have audited the accompanying consolidated balance sheet of Midstates Petroleum Company, Inc. and
subsidiary (‘‘Midstates’’) as of December 31, 2015, and the related consolidated statements of operations,
changes in stockholders’ equity (deficit), and cash flows for each of the two years in the period ended
December 31, 2015. These financial statements are the responsibility of Midstates’ 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. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An
audit also includes 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, such consolidated financial statements present fairly, in all material respects, the financial
position of Midstates Petroleum Company, Inc. and subsidiary as of December 31, 2015, and the results of
their operations and their cash flows for each of the two years in the period ended December 31, 2015, in
conformity with accounting principles generally accepted in the United States of America.
The accompanying 2015 and 2014 consolidated financial statements have been prepared assuming that
Midstates will continue as a going concern. Midstates’ event of default under the Credit Facility in 2015, a
projected additional debt covenant violation, and resulting lack of liquidity as of December 31, 2015 and
2014 raised substantial doubt about its ability to continue as a going concern. The consolidated financial
statements as of December 31, 2015 and for the two years in the period ended December 31, 2015 do not
include any adjustments that might result from the outcome of this uncertainty.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 30, 2016
F-3
MIDSTATES PETROLEUM COMPANY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
Successor
Predecessor
December 31, 2016 December 31, 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable:
$
Oil and gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Joint interest billing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting . . . . . . . . . . . . . . . .
Proved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unproved properties not being amortized . . . . . . . . . . . . . . . . . . . . . . . . .
Other property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depreciation, depletion, amortization and impairment . . . . . . . .
Net property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
OTHER NONCURRENT ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
76,838
$
36,988
4,281
2,456
3,326
123,889
573,150
65,080
6,339
(12,974)
631,595
5,455
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
760,939
$
LIABILITIES AND EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . .
Debt classified as current less unamortized debt issuance costs
$
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current liabilities
LONG-TERM LIABILITIES:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations
Long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2,521
53,731
—
56,252
14,200
128,059
614
142,873
COMMITMENTS AND CONTINGENCIES (Note 16)
STOCKHOLDERS’ EQUITY (DEFICIT):
Predecessor preferred stock, $0.01 par value, 49,675,000 shares authorized; no
shares issued or outstanding at December 31, 2015 . . . . . . . . . . . . . . . . . . .
Predecessor series A mandatorily convertible preferred stock, $0.01 par value, 8%
cumulative dividends; no shares issued or outstanding at December 31, 2015 . . .
Predecessor common stock, $0.01 par value, 100,000,000 shares authorized;
10,962,105 shares issued and 10,865,814 shares outstanding at December 31, 2015
Predecessor treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Predecessor additional paid-in-capital
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Successor preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares
issued or outstanding at December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . .
Successor warrants, 6,625,554 warrants outstanding at December 31, 2016 . . . . . .
Successor common stock, $0.01 par value, 250,000,000 shares authorized;
24,994,867 shares issued and 24,994,867 shares outstanding at December 31, 2016
Successor treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Successor additional paid-in-capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ equity (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
—
—
—
37,329
250
—
514,305
9,930
561,814
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
760,939
$
81,093
33,656
12,503
17,506
1,044
145,802
3,666,403
—
14,798
(3,157,332)
523,869
9,496
679,167
1,904
91,712
1,890,944
1,984,560
18,708
—
1,965
20,673
—
—
110
(3,081)
888,247
—
—
—
—
—
(2,211,342)
(1,326,066)
679,167
The accompanying notes are an integral part of these consolidated financial statements.
F-4
MIDSTATES PETROLEUM COMPANY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
Successor
Predecessor
Period
October 21, 2016
through
December 31, 2016
Period
January 1, 2016
through
October 20, 2016
For the Years Ended
December 31,
2015
2014
REVENUES:
Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Natural gas liquid sales . . . . . . . . . . . . . . . . . .
Natural gas sales
. . . . . . . . . . . . . . . . . . . . . .
. .
Gains on commodity derivative contracts—net
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total revenues . . . . . . . . . . . . . . . . . . . . . . .
EXPENSES:
Lease operating and workover . . . . . . . . . . . . .
Gathering and transportation . . . . . . . . . . . . . .
Severance and other taxes . . . . . . . . . . . . . . . .
Asset retirement accretion . . . . . . . . . . . . . . . .
Depreciation, depletion, and amortization . . . . .
Impairment in carrying value of oil and gas
properties . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . .
Acquisition and transaction costs
. . . . . . . . . . .
Debt restructuring costs and advisory fees . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total expenses . . . . . . . . . . . . . . . . . . . . . . .
OPERATING INCOME (LOSS) . . . . . . . . . . . . .
OTHER INCOME (EXPENSE):
Interest income . . . . . . . . . . . . . . . . . . . . . . .
Interest expense—net of amounts capitalized
(Predecessor Period excludes interest expense
of $89.5 million on senior and secured notes) .
Reorganization items, net (Note 3) . . . . . . . . . .
Total other income (expense) . . . . . . . . . . . .
INCOME (LOSS) BEFORE TAXES . . . . . . . . . . .
Income tax (expense) benefit . . . . . . . . . . . . . .
NET INCOME (LOSS)
. . . . . . . . . . . . . . . . . . . $
Predecessor preferred stock dividend . . . . . . . . .
Predecessor participating securities—Series A
Preferred Stock . . . . . . . . . . . . . . . . . . . . . .
Predecessor participating securities—non-vested
restricted stock . . . . . . . . . . . . . . . . . . . . . .
Successor participating securities—non-vested
restricted stock . . . . . . . . . . . . . . . . . . . . . .
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON SHAREHOLDERS . . . . . . . . . . . . . $
Basic and diluted net income (loss) per share
attributable to common shareholders . . . . . . . . . $
Basic and diluted weighted average number of
25,549
8,391
13,635
—
950
48,525
15,324
3,194
1,286
210
12,974
—
4,864
—
—
—
37,852
10,673
—
(743)
—
(743)
9,930
—
9,930
—
—
—
(280)
9,650
0.39
$
$
$
112,628
27,473
48,318
—
4,809
193,228
52,803
14,362
5,210
1,414
62,302
232,108
22,362
—
7,590
—
398,151
$
217,636
38,249
66,823
40,960
1,477
365,145
81,473
15,546
8,605
1,610
198,643
1,625,776
38,703
330
36,141
2,121
2,008,948
(204,923)
(1,643,803)
$ 466,655
87,771
99,204
139,189
1,364
794,183
79,598
13,404
24,266
1,706
269,935
86,471
48,733
4,129
—
5,108
533,350
260,833
81
115
39
(66,360)
1,594,281
1,528,002
1,323,079
—
(163,148)
—
(137,548)
—
(163,033)
(137,509)
(1,806,836)
9,641
123,324
(6,395)
$
1,323,079
$(1,797,195) $ 116,929
—
—
(16,522)
—
(948)
(10,378)
—
—
—
(35,696)
(3,584)
—
1,306,557
$(1,798,143) $ 67,271
122.74
$
(232.74) $
10.13
common shares outstanding (Note 14) . . . . . . . .
25,009
10,645
7,726
6,644
The accompanying notes are an integral part of these consolidated financial statements.
F-5
MIDSTATES PETROLEUM COMPANY, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)
(See Notes 11 and 12 for share history)
(In thousands)
Series A
Preferred Common
Stock
Stock Warrants
Treasury
Stock
Additional
Paid-in-Capital
Retained
Earnings
(Deficit)
Total
Stockholders’
Equity
(Deficit)
Balance as of December 31,
2013 (Predecessor) . . . . . . . . $
Share-based compensation . .
Acquisition of treasury stock .
Net income . . . . . . . . . . . . .
Balance as of December 31,
2014 (Predecessor) . . . . . . . . $
Share-based compensation . .
Acquisition of treasury stock .
Net loss . . . . . . . . . . . . . . .
Conversion of preferred
3 $
—
—
—
3 $
—
—
—
69 $ — $ (664) $
—
—
— (1,928)
—
—
1
—
—
871,667 $ (531,076) $
10,861
—
—
—
—
116,929
339,999
10,862
(1,928)
116,929
70 $ — $(2,592) $
—
—
— (489)
—
—
3
—
—
882,528 $ (414,147) $
465,862
5,756
—
5,753
—
(489)
—
— (1,797,195) (1,797,195)
shares . . . . . . . . . . . . . . .
(3)
37
—
—
(34)
—
—
Balance as of December 31,
2015 (Predecessor) . . . . . . . . $ — $
Share-based compensation . .
Acquisition of treasury stock .
Net income . . . . . . . . . . . . .
—
—
—
Balance as of October 21, 2016
(Predecessor) . . . . . . . . . . . $ — $
Cancellation of predecessor
110 $ — $(3,081) $
—
—
—
—
(53)
—
(6)
—
—
888,247 $(2,211,342) $(1,326,066)
3,039
(53)
1,323,079
—
3,045
—
—
— 1,323,079
104 $ — $(3,134) $
891,292 $ (888,263) $
(1)
equity . . . . . . . . . . . . . . .
— (104)
— 3,134
(891,292)
888,263
Balance as of October 21, 2016
(Predecessor) . . . . . . . . . . . $ — $ — $ — $ — $
— $
— $
1
—
Issuance of successor
common stock . . . . . . . . .
Issuance of successor
warrants . . . . . . . . . . . . . .
—
—
247
—
— 37,329
—
—
510,905
—
—
—
511,152
37,329
Balance as of October 21, 2016
(Successor) . . . . . . . . . . . . . $ — $
Issuance of successor
247 $37,329 $ — $
510,905 $
— $
548,481
common stock . . . . . . . . .
Share-based compensation . .
Net income . . . . . . . . . . . . .
—
—
—
3
—
—
—
—
—
—
—
—
—
3,400
—
—
—
9,930
3
3,400
9,930
Balance as of December 31,
2016 (Successor) . . . . . . . . . $ — $
250 $37,329 $ — $
514,305 $
9,930 $
561,814
The accompanying notes are an integral part of these consolidated financial statements.
F-6
MIDSTATES PETROLEUM COMPANY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Successor
Predecessor
Period October 21, 2016
through December 31,
2016
Period January 1, 2016
through October 20,
2016
Years Ended
December 31,
2015
2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
Adjustments to reconcile net income/(loss) to net
. . . . . . . . . . . . . . . . . . . .
$
9,930
$
1,323,079
$(1,797,195)
$ 116,929
cash provided by operating activities:
(Gains) losses on commodity derivative
contracts—net . . . . . . . . . . . . . . . . . . . .
Net cash received (paid) for commodity
derivative contracts not designated as hedging
. . . . . . . . . . . . . . . . . . . . .
instruments
Asset retirement accretion . . . . . . . . . . . . . .
Depreciation, depletion, and amortization . . . .
Impairment in carrying value of oil and gas
properties
. . . . . . . . . . . . . . . . . . . . . .
Share-based compensation, net of amounts
capitalized to oil and gas properties
. . . . . .
Deferred income taxes . . . . . . . . . . . . . . . .
Amortization of deferred financing costs . . . . .
Paid-in-kind interest expense . . . . . . . . . . . .
Amortization of deferred gain on debt
restructuring . . . . . . . . . . . . . . . . . . . . .
Operating lease abandonment
. . . . . . . . . . .
Non-cash reorganization items . . . . . . . . . . .
Transaction costs for debt restructuring . . . . . . .
Change in operating assets and liabilities:
Accounts receivable—oil and gas sales . . . . . .
Accounts receivable—JIB and other . . . . . . . .
Other current and noncurrent assets
. . . . . . .
Accounts payable . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . .
Other
Net cash provided by operating activities . . . . .
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment . . . . . . . .
Proceeds from the sale of oil and gas properties . .
Net cash used in investing activities . . . . . . . .
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings . . . . . . . . .
Proceeds from revolving credit facility . . . . . . . .
Repayment of long-term borrowings . . . . . . . . .
Repayment of revolving credit facility . . . . . . . .
Deferred financing costs
. . . . . . . . . . . . . . . .
Transaction costs for debt restructuring . . . . . . .
Acquisition of treasury stock . . . . . . . . . . . . . .
Net cash provided by financing activities . . . . .
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS . . . . . . . . . . . . . . . . .
Cash and cash equivalents, beginning of period . . .
Cash and cash equivalents, end of period . . . . . . .
$
$
$
$
$
$
$
$
—
—
210
12,974
—
2,909
—
63
—
—
—
—
—
(115)
(1,812)
1,783
(1,555)
(740)
(3)
23,644
(23,346)
—
(23,346)
$
$
$
— $
—
—
—
—
—
—
— $
298
76,540
76,838
$
$
$
—
(40,960)
(139,189)
—
1,414
62,302
167,669
1,610
198,643
(18,332)
1,706
269,935
232,108
1,625,776
86,471
2,564
—
4,587
3,531
(8,246)
1,574
(1,630,873)
—
(2,391)
22,002
(5,868)
1,797
55,160
(743)
4,408
(9,641)
11,316
6,415
(14,948)
—
—
34,398
26,437
22,833
590
(4,176)
(20,887)
1,095
8,618
5,586
7,857
—
—
—
—
—
33,322
(18,897)
3,191
2,327
(7,733)
(247)
61,997
$
213,383
$ 351,544
(133,307)
—
$ (336,922)
42,366
$(556,397)
152,133
(133,307)
$ (294,556)
$(404,264)
— $
249,384
(60,000)
(121,324)
(1,250)
—
(53)
66,757
(4,553)
81,093
76,540
$
$
$
$
625,000
33,000
—
(468,150)
(4,254)
(34,398)
(489)
$
—
165,000
—
(131,000)
(958)
—
(1,928)
150,709
$ 31,114
69,536
11,557
$ (21,606)
$ 33,163
81,093
$ 11,557
The accompanying notes are an integral part of these consolidated financial statements.
F-7
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements
1. Organization and Business
Midstates Petroleum Company, Inc. engages in the business of drilling for, and the production of,
oil, natural gas liquids (‘‘NGLs’’) and natural gas in Oklahoma and Texas. Midstates Petroleum
Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to
become a holding company for Midstates Petroleum Company LLC (‘‘Midstates Sub’’), which was
previously a wholly-owned subsidiary of Midstates Petroleum Holdings LLC (‘‘Holdings LLC’’).
Pursuant to the terms of a corporate reorganization that was completed in connection with the closing
of Midstates Petroleum Company, Inc.’s initial public offering, all of the interests in Midstates
Petroleum Holdings LLC were exchanged for newly issued common shares of Midstates Petroleum
Company, Inc., and as a result, Midstates Petroleum Company LLC became a wholly-owned subsidiary
of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a
separate entity. The terms ‘‘Company,’’ ‘‘we,’’ ‘‘us,’’ ‘‘our,’’ and similar terms when used in the present
tense, prospectively or for historical periods since April 25, 2012, refer to Midstates Petroleum
Company, Inc. and its subsidiary.
On March 5, 2014, the Company executed a Purchase and Sale Agreement (‘‘PSA’’) to sell all of
its ownership interest in developed and undeveloped acreage in the Pine Prairie field area of
Evangeline Parish, Louisiana to a private buyer for net proceeds of $147.7 million in cash (the ‘‘Pine
Prairie Disposition’’). Acreage subject to the transaction did not include acreage and production in the
western part of Louisiana in Beauregard or Calcasieu Parishes or other undeveloped acreage held
outside the Pine Prairie field. The sale closed on May 1, 2014.
On April 21, 2015, the Company closed the sale of all of its ownership interest in its Dequincy
assets, which constituted its remaining producing and proved reserve properties in Louisiana (the
‘‘Dequincy Divestiture’’) to Pintail Oil and Gas LLC. The net proceeds, inclusive of amounts placed in
escrow, were approximately $42.4 million. With the completion of the Dequincy Divestiture, the
Company no longer has any operations in the Louisiana/Gulf Coast area, although it continues to have
approximately 4,431 net acres of undeveloped acreage under lease in Louisiana.
On February 3, 2016, the Company received notice from the New York Stock Exchange (‘‘NYSE’’)
that the Company’s common stock no longer met the NYSE continued listing requirements. As a
result, the Company’s common stock was automatically delisted from the NYSE and began trading on
an over the counter exchange under the symbol ‘‘MPOY’’. On April 30, 2016, we filed voluntary
petitions for reorganization under Chapter 11 of the United States Bankruptcy Code. On October 21,
2016, in connection with our emergence from Chapter 11 as discussed further below, our existing
common shares traded under the symbol MPOY were cancelled and on October 24, 2016, our new
common shares issued in connection with our successful reorganization and emergence from
Chapter 11 were listed and began trading on the NYSE MKT under the symbol ‘‘MPO’’.
2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings
On April 30, 2016 (the ‘‘Petition Date’’), the Company filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code (the ‘‘Bankruptcy Code’’) in the United States
Bankruptcy Court for the Southern District of Texas (the ‘‘Bankruptcy Court’’). The Company’s
Chapter 11 cases (the ‘‘Chapter 11 Cases’’) were jointly administered under the case styled In re
Midstates Petroleum Company, Inc., et al., Case No. 16-32237. On September 28, 2016, the Bankruptcy
Court entered the Findings of Fact, Conclusions of Law, and Order Confirming Debtors’ First Amended
Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate (the
F-8
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings (Continued)
‘‘Confirmation Order’’), which approved and confirmed the First Amended Joint Chapter 11 Plan of
Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on the same
date (the ‘‘Plan’’). On October 21, 2016 (the ‘‘Effective Date’’), the Company satisfied the conditions to
effectiveness set forth in the Confirmation Order and in the Plan, and, as a result, the Plan became
effective in accordance with its terms and the Company emerged from the Chapter 11 Cases.
Plan of Reorganization
Pursuant to the confirmed Plan, the significant transactions that occurred upon the Effective Date
were as follows:
(cid:127) Substantial Deleveraging of the Balance Sheet: (i) The permanent pay-down of $81.3 million of
the Company’s revolving credit facility (‘‘RBL’’), with a $170.0 million exit facility (the ‘‘Exit
Facility’’) established upon the Effective Date, (ii) the pay-down of $60.0 million of the
Company’s Second Lien Notes in cash and (iii) the conversion into equity of all of the
Company’s remaining debt junior to the RBL;
(cid:127) Credit Facility Claims: Holders of allowed claims arising under the RBL (the ‘‘Credit Facility
Claims’’) received their pro rata share of approximately $81.3 million in cash and the RBL was
superseded, pursuant to the Plan, by the Exit Facility, as further described below;
(cid:127) Second Lien Notes Claims: Holders of allowed claims arising under the Second Lien Notes (the
‘‘Second Lien Notes Claims’’) received their pro rata share of (i) 96.25% of the reorganized
equity in the form of common stock and (ii) a cash payment of $60.0 million;
(cid:127) Third Lien Notes Claims: Holders of allowed claims arising under the Third Lien Notes (the
‘‘Third Lien Notes Claims’’), pursuant to a settlement with holders of Second Lien Notes Claims
on terms more fully set forth in the Plan (the ‘‘Second/Third Lien Plan Settlement’’), received
their pro rata share of 2.5% of the reorganized equity in the form of common stock and
warrants to acquire 4,411,765 shares of common stock at a strike price of $24.00 per common
share with an expiration date 42 months after the Effective Date;
(cid:127) Unsecured Claims: Holders (the ‘‘Unsecured Noteholders’’) of allowed claims arising under the
Debtors’ 10.75% Senior Unsecured Notes due 2020 (the ‘‘2020 Notes Claims’’), the holders of
allowed claims arising under the 9.25% Senior Unsecured Notes due 2021 (the ‘‘2021 Notes
Claims’’ and together with the 2020 Notes Claims, the ‘‘Unsecured Notes Claims’’), and the
Holders of other general unsecured claims received their pro rata share of 1.25% of reorganized
equity in the form of common stock and warrants to acquire 2,213,789 shares of common stock
(the ‘‘Unencumbered Assets Equity Distribution’’) at a strike price of $46.00 per common share
with an expiration date 42 months after the Effective Date;
(cid:127) Existing Equity: All existing equity interests were extinguished and existing equity holders did
not receive any consideration in respect of their equity interests;
(cid:127) New Equity: On the Effective Date, the Company issued 24,687,500 shares of common stock of
the reorganized Company. On November 9, 2016, the Company issued an additional
294,967 shares of common stock of the reorganized Company pursuant to the Plan. The
Company will issue 17,533 additional common shares, with respect to general unsecured claims,
F-9
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings (Continued)
pursuant to the Plan in a future distribution. The total authorized reorganized capital stock
consists of 250,000,000 shares of common stock and 50,000,000 shares of preferred stock;
(cid:127) Exit Facility: The Company’s RBL, which was redetermined with a borrowing base of
$170.0 million in April 2016, was superseded, pursuant to the Plan, by the Exit Facility. The Exit
Facility has an initial borrowing base of $170.0 million with no borrowing base redeterminations
to occur until April 2018 (provided certain conditions are met) and semiannual borrowing base
redeterminations each year on April 1 and October 1 thereafter. Until April 2018, unless the
borrowing base is redetermined earlier, the amount available to be drawn under the Exit Facility
is reduced by $40.0 million, and thereafter, the Company must maintain liquidity (as defined
therein) equal to at least 20.0% of the effective borrowing base. In connection therewith, on the
Effective Date, the Company made an additional payment of $40.0 million to lenders under its
Exit Facility. See ‘‘—Note 10. Debt’’ for further information regarding the Exit Facility; and
(cid:127) Long-Term Incentive Plan: A management equity incentive plan (the ‘‘2016 LTIP’’) was
established under which 10.0% of the reorganized equity (on a fully-diluted/fully-distributed
basis) was reserved for grants to be made from time to time to the directors, officers, and other
members of management.
3. Fresh Start Accounting
Upon emergence on the Effective Date, the Company adopted fresh start accounting as required
by generally accepted accounting principles in the United States (‘‘US GAAP’’). The Company
qualified for fresh start accounting because (i) the holders of existing voting shares of the
pre-emergence debtor-in-possession received less than 50% of the voting shares of the post-emergence
successor entity and (ii) the reorganization value of the Company’s assets immediately prior to
confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh
start accounting as of October 21, 2016, the Effective Date.
Adopting fresh start accounting results in a new reporting entity for financial reporting purposes
with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding on the
Effective Date and issuance of new shares in the reorganized Company caused a related change of
control under US GAAP. As a result of the application of fresh start accounting, as well as the effects
of the implementation of the Plan, the Company’s consolidated financial statements on or after
October 21, 2016, are not comparable with the consolidated financial statements prior to that date.
References to ‘‘Successor Period’’ relate to the financial position and results of operations for the
period October 21, 2016 through December 31, 2016 and references to ‘‘Predecessor Period’’ refer to
the financial position and results of operations of the Company from January 1, 2016 through
October 20, 2016.
Reorganization Value
Reorganization value represents the fair value of the Company’s total assets prior to the
consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the
Company’s assets immediately after restructuring. The reorganization value was allocated to the
Company’s individual assets based on their estimated fair values.
F-10
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
3. Fresh Start Accounting (Continued)
The Company’s reorganization value was derived from enterprise value. Enterprise value
represents the estimated fair value of an entity’s long-term debt and equity. The enterprise value of the
Company on the Effective Date, as approved by the Bankruptcy Court in support of the Plan, was
estimated to be within a range of $500.0 million to $700.0 million, with a mid-point value of
$600.0 million. Based upon the various estimates and assumptions necessary for fresh start accounting,
as further discussed below, the estimated enterprise value was determined to be $600.0 million before
consideration of cash and cash equivalents and outstanding debt at the Effective Date. As a result, the
reorganization value was determined to be $751.3 million at the Effective Date, as reconciled below.
Valuation of Oil and Gas Properties
The Company’s principal assets are its oil and gas properties, which the Company accounts for
under the full cost accounting method as described in ‘‘—Note 4. Summary of Significant Accounting
Policies’’. With the assistance of valuation experts, the Company determined the fair value of its oil and
gas properties based on the discounted net cash flows expected to be generated from these assets. The
computations were based on market conditions and reserves in place as of the Effective Date.
The foundation for the computation of the fair value of the Company was a reserves report
prepared by its independent reserve auditors. The engineering assumptions contained within this
reserves report were consistent with both (i) previous engineering assumptions made by the Company
when preparing reserve reports in prior years and (ii) assumptions promulgated by the Securities and
Exchange Commission (‘‘SEC’’). These assumptions include type curves and analogous reservoir
characteristics determined utilizing electrical logs, radioactivity logs, core analyses, geologic maps and
available downhole and production data, seismic data and well test data, to name a few.
Upon completion of the Company’s reserves report, it utilized outside third-party experts to assist
management in the preparation of a valuation report utilizing assumptions consistent with a market
participant. This valuation report utilized the income approach in determining the fair value of the
Company’s oil and gas reserves, excluding possible reserves, for which the market approach was
utilized. The income approach involves the projection of cash flows a market participant would expect
an asset or business to generate over its remaining useful life. Cash flows are projected on an annual
basis for a discrete period of time and then converted to their present value using a rate of return that
captures the relevant risk of achieving the projected cash flows. Finally, the present value of the
residual value, or terminal value, is added to these discrete cash flows to arrive at the estimate of total
value. The market approach measures value through the use of prices, market multiples and other
relevant information involving identical or comparable assets or business interests. The significant
assumptions utilized within the valuation report included the following:
(cid:127) Pricing—The Company utilized pricing based on the six year New York Mercantile Exchange
strip as of the Effective Date. NGL prices were based upon a historical percentage correlation
of the price of West Texas Intermediate to the price of a Y-grade barrel. Prices beyond six years
were escalated at 2.0% to account for inflation. Price differentials that have been calculated
utilizing historical results were applied to account for quality and transportation differentials.
(cid:127) Weighted-Average Cost of Capital (‘‘WACC’’)—The WACC reflects the required return of
capital providers, both debt and equity. Eight guideline companies were selected that had
operations in the Mid-Continent area and were organized as C-corporations. A cost of equity
was calculated using a capital asset pricing model, in which the cost of equity equals a risk-free
F-11
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
3. Fresh Start Accounting (Continued)
rate plus a risk premium that is reflective of the asset or business interest. The risk free rate
utilized was 2.2% based upon the normalized 20-year U.S. Treasury Bond rate as of the
Effective Date. The risk premium was calculated utilizing three primary inputs. First, a beta was
determined based upon the respective two-year weekly betas for each guideline company,
adjusted for debt of their capital structures and then re-levered using the selected Company
capital structure. Next, a market risk premium of 6.0% was utilized based upon industry data.
Finally, a size premium of 3.6% was applied based upon the size of the interest in the assets of
the Company utilizing industry data. A cost of debt was then calculated to be approximately
7.0% based upon the weighted average energy yield of the guideline companies at the Effective
Date and then adjusted for a 35.0% tax effective to arrive at an estimated after-tax cost of debt
of 4.6%. Based upon these inputs, the capital asset pricing model arrived at a WACC of 11.0%,
which was utilized by the Company in its determination of fair value.
(cid:127) Operating and Other Costs—Operating costs from the reserves report prepared by the Company
were escalated by 2.0% to account for inflation. Ad valorem and production taxes were
estimated as a percentage of revenue and applied to the forward price adjusted revenues.
Corporate general and administrative costs were estimated based a blend of historical general
and administrative expenses and forecasts of such expenses for the next five years. Corporate
general and administrative expenses were escalated at 2.0% after five years to account for
inflation.
(cid:127) Capital Expenditures—Capital expenditures were based upon the average historical capital
expended by the Company in the development of its wells and were escalated by 2.0% to
account for inflation.
(cid:127) Possible Reserves—The Company utilized the guideline transaction method to determine the
value of possible reserve acreage. In determining the value of possible reserve acreage, the
Company utilized data from widely utilized industry sources as well as data from other relevant
transactions in the area. These industry sources publish oil and gas lease data compiled from
private transactions, federal oil and gas lease sales as well as state oil and gas lease sales. The
Company then utilized this data to arrive at a range of acreage values for each county.
Based upon the analysis completed by the Company with the assistance of outside third-party
valuation experts, it concluded the fair value of its proved reserves was $539.0 million and the value of
its probable and possible reserves, characterized as unproved properties, was $66.2 million as of the
Effective Date.
F-12
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
3. Fresh Start Accounting (Continued)
The following table presents the estimated fair value of the Company’s stock as of the Effective
Date (in thousands, except per share value):
As of
October 21, 2016
Enterprise value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plus: Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Fair value of debt
Less: Fair value of warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
600,000
76,540
(128,059)
(37,329)
Fair value of stock on the Effective Date . . . . . . . . . . . . . . . . . . . . .
$
511,152
Total shares issuable under the Plan . . . . . . . . . . . . . . . . . . . . . . . .
Restricted shares granted under 2016 LTIP at October 21, 2016 . . . .
Total shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Per share value(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
25,000
686
25,686
19.90
(1) The per share value shown above is calculated based upon the financial information
determined using US GAAP at the Effective Date. The fair value per share agreed upon
by the parties to the Chapter 11 Cases at the Effective Date was determined to be $19.66
per common share.
On the Effective Date, the Company entered into (i) a warrant agreement with holders of Allowed
Third Lien Notes Claims (the ‘‘Third Lien Notes Warrant Agreement’’) with respect to third lien
warrants (the ‘‘Third Lien Notes Warrants’’) and (ii) a warrant agreement with holders of Allowed
Unsecured Notes Claims and Allowed General Unsecured Claims (the ‘‘Unsecured Creditor Warrant
Agreement’’, and together with the Third Lien Notes Warrant Agreement, the ‘‘Warrant Agreements’’)
with respect to warrants (the ‘‘Unsecured Creditor Warrants’’, and together with the Third Lien Notes
Warrants, the ‘‘Warrants’’).
At the Effective Date, the Company issued 4,411,765 Third Lien Notes Warrants allowing for the
purchase of up to an aggregate of 4,411,765 shares of common stock at an initial exercise price of
$24.00 per share, and 2,213,789 Unsecured Creditor Warrants allowing for the purchase of up to an
aggregate of 2,213,789 shares of common stock at an initial exercise price of $46.00 per share. The
Warrants expire on April 21, 2020.
The Company utilized the Black-Scholes-Merton option pricing model to determine the fair value
of the Warrants. Determining the fair value of the Warrants required judgment, including estimating
the expected term and the associated volatility.
F-13
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
3. Fresh Start Accounting (Continued)
The assumptions used to estimate the fair value the Warrants are as follows:
Third Lien Notes
Warrants
Unsecured
Creditor Warrants
Risk-free interest rate(1) . . . . . . . . . . . . . . . . . . .
Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected life(2) . . . . . . . . . . . . . . . . . . . . . . . . .
Expected volatility(3) . . . . . . . . . . . . . . . . . . . . .
Strike Price . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Calculated fair value . . . . . . . . . . . . . . . . . . . . . .
$
$
1.04%
—
3.50
55.0%
24.00
6.74
$
$
1.04%
—
3.50
55.0%
46.00
3.42
(1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate
assumption, matching the treasury yield terms to the expected life of the option.
(2) The expected life assumption was based upon the years until expiration of the Warrants.
(3) The Company utilized six peer companies of comparable size and industry to estimate
asset volatility utilizing a period that is commensurate with the expected Warrant life. The
Company weighted historical volatility and implied volatility 50/50 for those peer
companies where both were available, with asset volatility ranging in the peer companies
from 30.1% to 54.2%. The derived asset volatility was selected based upon the midpoint
of the average and the third quartile of the peer group, and then relevered the utilizing
the Company’s asset and equity information as of the Effective Date.
The following table reconciles the enterprise value to the estimated reorganization value as of the
Effective Date (in thousands):
Enterprise value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plus: cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plus: other working capital liabilities . . . . . . . . . . . . . . . . . . . . . . . .
Plus: other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Reorganization value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
600,000
76,540
60,118
14,600
751,258
As of
October 21, 2016
F-14
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
3. Fresh Start Accounting (Continued)
Consolidated Balance Sheet
The following consolidated balance sheet is as of October 21, 2016. This consolidated balance
sheet includes adjustments that reflect the consummation of the transactions contemplated by the Plan
(reflected in the column ‘‘Reorganization Adjustments’’) as well as fair value adjustments as a result of
the adoption of fresh start accounting (reflected in the column ‘‘Fresh Start Adjustments’’) as of the
Effective Date (in thousands):
Predecessor
Reorganization
Adjustments
Fresh Start
Adjustments
Successor
ASSETS
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . $
Accounts receivable:
Oil and gas sales . . . . . . . . . . . . . . .
Joint interest billing . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . .
274,530 $
(197,990) {a}
$
33,895
4,739
26
8,425
—
—
—
(2,748) {b}
Total current assets
. . . . . . . . . . . . .
321,615
(200,738)
—
—
—
—
—
—
$ 76,540
33,895
4,739
26
5,677
120,877
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of
full-cost accounting . . . . . . . . . . . . .
Other property and equipment . . . . . . .
Less accumulated depreciation,
depletion, amortization and
impairment . . . . . . . . . . . . . . . . . . .
3,795,943
12,175
(3,449,241)
Net property and equipment . . . . . . .
OTHER NONCURRENT ASSETS . . . . .
358,877
3,701
—
—
—
—
1,250 {c}{a}
(3,176,723) {h}
(5,965) {h}
619,220
6,210
3,449,241 {h}
—
266,553
—
625,430
4,951
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . $
684,193 $
(199,488)
$
266,553
$751,258
F-15
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
3. Fresh Start Accounting (Continued)
LIABILITIES AND STOCKHOLDERS’
EQUITY/(DEFICIT)
CURRENT LIABILITIES:
Predecessor
Reorganization
Adjustments
Fresh Start
Adjustments
Successor
Accounts payable . . . . . . . . . . . . . . . . . $
Accrued liabilities . . . . . . . . . . . . . . . .
Debt classified as current . . . . . . . . . . .
10,294 $
65,240
249,384
—
(15,416) {a}
(249,384) {a}{d}
$
Total current liabilities . . . . . . . . . . .
324,918
(264,800)
—
—
—
—
$ 10,294
49,824
—
60,118
ASSET RETIREMENT OBLIGATIONS .
OTHER LONG-TERM LIABILITIES . . .
LIABILITIES SUBJECT TO
20,368
617
—
128,059
{d}
(6,385) {h}
—
13,983
128,676
COMPROMISE . . . . . . . . . . . . . . . . .
1,882,187
(1,882,187) {e}{a}
—
—
COMMITMENTS AND
CONTINGENCIES
STOCKHOLDERS’ EQUITY/
(DEFICIT):
Preferred stock . . . . . . . . . . . . . . . . . .
Warrants . . . . . . . . . . . . . . . . . . . . . . .
Common stock—predecessor . . . . . . . .
Common stock—successor . . . . . . . . . .
Treasury stock . . . . . . . . . . . . . . . . . . .
Additional paid-in-capital—predecessor .
Additional paid-in-capital—successor . .
Retained deficit . . . . . . . . . . . . . . . . . .
—
—
104
—
(3,134)
891,292
—
(2,432,159)
—
37,329
(104)
247
3,134
(891,292)
510,905
2,159,221
{e}
{f}
{f}
{f}
{f}
{f}
{g}
Total stockholders’ equity/(deficit) . . .
(1,543,897)
1,819,440
—
—
—
—
—
—
—
272,938 {i}
272,938
—
37,329
—
247
—
—
510,905
—
548,481
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . $
684,193 $
(199,488)
$
266,553
$751,258
Reorganization Adjustments
{a} Adjustments reflect the following net cash payments recorded as of the Effective Date from
implementation of the Plan (in thousands):
Uses:
Cash pay down of RBL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash payment to holders of Second Lien Notes Claims . . . . . . . . . . . . . .
Cash payment to the RBL lenders in consideration of a temporary
$ 81,324
60,000
reduction in the amount available to be drawn under the Exit Facility . .
40,000
Payment to escrow for professional fees related to the Plan incurred
through the Effective Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt issuance costs associated with the Exit Facility . . . . . . . . . . . . . . . . .
15,416
1,250
Total uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$197,990
{b} Adjustment reflects the write off of unamortized debt issuance costs associated with the RBL.
F-16
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
3. Fresh Start Accounting (Continued)
{c} Adjustment reflects the debt issuance costs associated with the Exit Facility.
{d} Adjustment represents the establishment of Exit Facility, which superceded the RBL.
{e} As part of the Plan, the Bankruptcy Court approved the settlement of certain allowable claims,
reported as liabilities subject to compromise in the Company’s historical consolidated balance
sheet. As a result, a gain of $1.3 billion was recognized on the settlement of liabilities subject to
compromise. The gain was calculated as follows (in thousands):
Liabilities subject to compromise . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash paid to holders of Second Lien Notes Claims . . . . . . . . . . . . . . . .
Warrants issued to holders of Third Lien Notes Claims . . . . . . . . . . . . .
Warrants issued to holders of Unsecured Notes Claims . . . . . . . . . . . . .
Write-off of unamortized debt costs associated with RBL . . . . . . . . . . .
Common stock issued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Predecessor
$1,882,187
(60,000)
(29,753)
(7,575)
(2,748)
(511,152)
Gain on settlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,270,959
{f} Adjustments represent (i) the cancellation of predecessor stock that was authorized and
outstanding prior to the Effective Date and (ii) the issuance of 24,687,500 shares of new common
stock upon emergence on the Effective Date.
{g} This adjustment reflects the cumulative impact of the following reorganization adjustments (in
thousands):
Gain on settlement of liabilities subject to compromise . . . . . . . . . . . . .
Common stock—predecessor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in-capital—predecessor . . . . . . . . . . . . . . . . . . . . . . . .
Predecessor
$1,270,959
104
(3,134)
891,292
Net impact to Predecessor accumulated deficit . . . . . . . . . . . . . . . . . . .
$2,159,221
Fresh Start Adjustments
{h} The adjustments primarily represent (i) the removal of $3.4 billion of accumulated depreciation,
depletion, amortization and impairment due to fresh start accounting, (ii) the $269.7 million
increase in oil and gas properties due to the application of fresh start accounting, (iii) the
$6.4 million decrease in the asset retirement obligation due to the application of fresh start
accounting and (iv) an increase in other property and equipment.
{i} This adjustment reflects the cumulative impact of the fresh start adjustments discussed herein.
Reorganization Items
Reorganization items represent the direct and incremental costs of being in bankruptcy, such as
professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that
are probable and can be estimated. Unamortized deferred financing costs as well as unamortized gains
F-17
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
3. Fresh Start Accounting (Continued)
on the May 2015 troubled debt restructuring associated with debt classified as liabilities subject to
compromise were also reclassified to reorganization items in order to reflect the expected amounts of
allowed claims. The following table summarizes the gain on reorganization items, net, in the
consolidated statements of operations (in thousands):
Predecessor
For the Period January 1,
2016 through
October 20, 2016
Professional fees incurred . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustment to unamortized debt issuance costs associated
$
with 2020 Senior Notes . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustment to unamortized debt issuance costs associated
with 2021 Senior Notes . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustment to unamortized gain on troubled debt
restructuring associated with Second Lien Notes . . . . . . . . .
Adjustment to unamortized gain on troubled debt
restructuring associated with Third Lien Notes . . . . . . . . . .
Gain on settlement of liabilities subject to compromise . . . . .
Fresh start adjustments
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other reorganization items(1) . . . . . . . . . . . . . . . . . . . . . . . .
Gain on reorganization items, net . . . . . . . . . . . . . . . . . . . . .
$
(38,835)
(10,738)
(12,671)
39,599
71,808
1,270,959
272,938
1,221
1,594,281
(1) Other reorganization items recorded for October 20, 2016 primarily included $0.2 million
related to Houston office fixed assets, which were abandoned, as well as a $1.6 million
decrease in the liability previously recorded for the abandonment of the Houston office
lease.
4. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company have been prepared pursuant
to the rules and regulations of the SEC and have been prepared in accordance with US GAAP.
All intercompany transactions have been eliminated in consolidation. The consolidated financial
statements for the period October 21, 2016 through December 31, 2016 are referred to as the
Successor Period, and the period January 1, 2016 through October 20, 2016 is referred to as the
Predecessor Period. The consolidated financial statements as of and for the year ended December 31,
2015 include the results of the Dequincy Divestiture from January 1, 2015 through April 21, 2015, the
date of disposition. The consolidated financial statements as of and for the year ended December 31,
2014 include the results of the Pine Prairie Disposition from January 1, 2014 through May 1, 2014, the
date of disposition. The Company’s management evaluates performance based on one reportable
segment as all its operations are located in the United States and therefore it maintains one cost
center.
F-18
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
4. Summary of Significant Accounting Policies (Continued)
Fresh Start Accounting
Upon emergence from bankruptcy, the Company adopted fresh start accounting. Adopting fresh
start accounting results in a new reporting entity for financial reporting purposes with no beginning
retained earnings or deficit. As a result of the application of fresh start accounting, as well as the
effects of the implementation of the Plan, the Company’s consolidated financial statements on or after
October 21, 2016 are not comparable with the Company’s consolidated financial statements prior to
that date.
Use of Estimates
The preparation of financial statements in conformity with US GAAP requires management to
make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. The Company utilizes historical experience as well
as other assumptions that are believed to be reasonable under the circumstances in preparing its
estimates. The Company evaluates estimates and assumptions on a regular basis. Actual results could
differ from those estimates and assumptions used in the preparation of the Company’s financial
statements.
Significant estimates include, but are not limited to the estimates of reorganization value,
enterprise value and fair value of assets and liabilities upon emergence from bankruptcy and
application of fresh start accounting, the estimate of recoverable oil and natural gas reserves and
related present value estimates of future net cash flows derived therefrom, legal and environmental
risks and exposures, the fair value of share-based compensation, income taxes and the valuation of
future asset retirement obligations.
Cash and Cash Equivalents
The Company considers all short-term investments with an original maturity of three months or
less to be cash equivalents. The Company’s total cash balances are insured by the Federal Deposit
Insurance Corporation (‘‘FDIC’’) up to $250,000 per bank per depositor. The Company had cash
balances on deposit at December 31, 2016 and 2015 that exceeded the balance insured by the FDIC in
the amount of $78.4 million and $87.2 million, respectively.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are stated at the historical carrying amount net of any allowance for
uncollectible accounts. The carrying amount of the Company’s accounts receivable approximate fair
value because of the short-term nature of the instruments. Many of the Company’s receivables are from
joint interest owners in properties in which the Company is the operator. The Company may withhold
future revenue disbursements to recover any non-payment of these joint interest billings under certain
circumstances. The Company routinely assesses the collectability of all material trade and other
receivables and the Company accrues a reserve on a receivable when, based on the judgment of
management, it is probable that a receivable will not be collected and the amount of any reserve may
be reasonably estimated. As of December 31, 2016 and 2015, the Company had no allowance for
doubtful accounts.
F-19
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
4. Summary of Significant Accounting Policies (Continued)
Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, receivables, payables,
debt, and commodity derivative contracts. Commodity derivative contracts are recorded at fair value;
see ‘‘—Note 5. Fair Value Measurements of Financial Instruments’’. The fair value of the Company’s
long-term debt is disclosed, see ‘‘—Note 10. Debt’’. The carrying amount of the Company’s other
financial instruments approximate fair value because of the short term nature of the items or variable
pricing.
Derivative financial instruments, if held by the Company, are presented in the consolidated balance
sheets as either an asset or liability measured at estimated fair value. Changes in the derivative’s fair
value are recognized in the consolidated statement of operations as gains and losses in the period of
change. The gains or losses are recorded in ‘‘Gains (losses) on commodity derivative contracts—net.’’
The related cash flow impact is reflected within cash flows from operating activities.
Other Noncurrent Assets
At December 31, 2016 and 2015, other noncurrent assets consisted of the following (in thousands):
Successor
Predecessor
December 31, 2016
December 31, 2015
Deferred financing costs associated with the RBL .
Deferred financing costs associated with the Exit
Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Field equipment inventory . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other noncurrent assets . . . . . . . . . . . . . . . . . . .
$
$
— $
1,187
2,619
1,649
5,455
$
6,105
—
3,225
166
9,496
For the Predecessor Period, approximately $4.6 million in deferred financing costs associated with
the RBL were impaired. For the year ended December 31, 2015, the Company recorded $2.0 million of
losses on the sale of, or market value adjustments to, field equipment inventory.
Property and Equipment
Oil and Gas Properties
The Company uses the full-cost method of accounting for its exploration and development
activities. Under this method of accounting, costs of both successful and unsuccessful exploration and
development activities are capitalized as property and equipment. This includes any internal costs that
are directly related to exploration and development activities, but does not include any costs related to
production, general corporate overhead or similar activities. Proceeds from the sale or disposition of oil
and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of
the Company’s reserve quantities are sold such that it results in a significant alteration of the
relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is
generally recognized in income.
F-20
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
4. Summary of Significant Accounting Policies (Continued)
Unevaluated Property
Oil and gas unevaluated properties and properties under development include costs that are not
being depleted or amortized. These costs represent investments in unproved properties. The Company
excludes these costs until proved reserves are found, until it is determined that the costs are impaired
or until major development projects are placed in service, at which time the costs are moved into oil
and natural gas properties subject to amortization. All unproved property costs are reviewed at least
annually to determine if impairment has occurred. In addition, impairment assessments are made for
interim reporting periods if facts and circumstances exist that suggest impairment may have occurred.
During any period in which impairment is indicated, the accumulated costs associated with the
impaired property are transferred to proved properties, become part of our depletion base and become
subject to the full cost ceiling limitation.
During 2015, the Company transferred the remaining unevaluated property balance consisting of
$56.3 million of Mississippian unevaluated property costs, $0.2 million of Anadarko Basin unevaluated
property costs and $0.1 million of Gulf Coast unevaluated property costs to the full cost pool as a
result of current pricing, its anticipated drilling plans and uncertainty regarding its ability to finance its
future exploration activities at that time. At the Effective Date, the Company recorded $66.2 million in
unevaluated property associated with fresh start accounting. See ‘‘—Note 3. Fresh Start Accounting’’
for further information.
Oil and Gas Reserves
Proved oil, NGLs and natural gas reserves utilized in the preparation of the consolidated financial
statements are estimated in accordance with the rules established by the SEC and the Financial
Accounting Standards Board (‘‘FASB’’), which require that reserve estimates be prepared under existing
economic and operating conditions using a 12-month average price with no provision for price and cost
escalations in future years except by contractual arrangements.
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as
more current information becomes available. The Company depletes its oil and gas properties using the
units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization
are depleted over proved reserves. It is possible that, because of changes in market conditions or the
inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues,
the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas
properties, or any combination of the above may be increased or reduced. Increases in recoverable
economic volumes generally reduce per unit depletion rates while decreases in recoverable economic
volumes generally increase per unit depletion rates.
Impairment of Oil and Gas Properties/Ceiling Test
The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit, or
ceiling, on the book value of oil and gas properties. The capitalized costs of proved oil and gas
properties, net of accumulated depreciation, depletion and amortization (‘‘DD&A’’) and the related
deferred income taxes, may not exceed this ceiling. The ceiling limitation is equal to the sum of: (i) the
present value of estimated future net revenues from the projected production of proved oil and gas
reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on
the balance sheet, calculated using the average oil and natural gas sales prices received by the
F-21
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
4. Summary of Significant Accounting Policies (Continued)
Company as of the first trading day of each month over the preceding twelve months (such prices are
held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of
unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or
estimated fair value of unproved properties included in the costs being amortized; and (iv) related
income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the
accompanying consolidated statements of operations. For the Predecessor Period, the Company
recorded an impairment of oil and gas properties of $232.1 million. For the years ended December 31,
2015 and 2014, the Company recorded impairments of oil and gas properties of $1.6 billion and
$86.5 million, respectively. A significant and sustained decline in the average oil and natural gas sales
price utilized in calculating the present value of estimated future net revenues from projected
production of oil and gas reserves was the primary factor that led to the full-cost ceiling impairments
for the Predecessor Period and the years ended December 31, 2015. For the year ended December 31,
2014, the primary factor affecting the impairment related to the transfer of unevaluated property costs
to the full cost pool.
Depletion
Depletion of oil and gas properties is calculated using the units of production method (‘‘UOP’’).
The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves
produced by the cost of those reserves. The result is to recognize expense at the same pace that the
reserves are estimated to be depleting. The amortization base in the UOP calculation includes the sum
of proved property costs net of accumulated depletion, estimated future development costs (future costs
to access and develop proved reserves) and asset retirement costs that are not already included in oil
and gas property, less related salvage value.
Capitalized Interest
Interest is capitalized for certain unevaluated oil and gas properties with ongoing development
activities using the weighted-average cost of outstanding borrowings, which also includes the
amortization of debt costs. Capitalized interest is depleted over the useful lives of the assets in the
same manner as the depletion of the underlying assets.
Other Property and Equipment
Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware
and software and is carried at cost. Depreciation is provided principally using the straight-line method
over the estimated useful lives of the assets, which primarily range from three to seven years.
Maintenance and repairs are charged to expense as incurred, while renewals and betterments are
capitalized.
F-22
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
4. Summary of Significant Accounting Policies (Continued)
Accrued Liabilities
At December 31, 2016 and 2015, accrued liabilities consisted of the following (in thousands):
Successor
Predecessor
December 31, 2016
December 31, 2015
Accrued oil and gas capital expenditures . . . . . . .
Accrued revenue and royalty distributions . . . . . .
Accrued lease operating and workover expense . .
Accrued interest
. . . . . . . . . . . . . . . . . . . . . . . .
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . . . . .
Compensation and benefit related accruals . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
6,118
28,262
8,932
254
2,537
3,516
4,112
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . .
$
53,731
$
19,984
27,939
9,281
20,193
1,272
8,414
4,629
91,712
Asset Retirement Obligations
The legal obligations associated with the retirement of long-lived assets are recognized at
estimated fair value at the time that the obligation is incurred.
Oil and gas producing companies incur such a liability upon drilling or acquiring a well. The
Company estimates the fair value of an asset retirement obligation in the period in which the obligation
is incurred and can be reliably measured. The corresponding asset retirement cost is capitalized by
increasing the carrying amount of the related long-lived asset. The liability is accreted to its then
present value each period, and the capitalized cost is depleted over the useful life of the related asset.
If the liability is settled for an amount other than the recorded amount, any adjustment is recorded to
the full cost pool. See ‘‘—Note 9. Asset Retirement Obligations’’.
Share-Based Compensation
The Company measures share-based compensation cost at fair value and generally recognizes the
corresponding compensation expense on a straight-line basis over the service period during which
awards are expected to vest for periods prior to the Effective Date. For periods subsequent to the
Effective Date, the Company recognizes compensation expense on a graded vesting basis. Share-based
compensation expense, net of amounts capitalized to oil and gas properties, is included in ‘‘General
and administrative expense’’ in our consolidated statements of operations and ‘‘Accrued liabilities’’ in
our consolidated balance sheets. See ‘‘—Note 12. Equity and Share-Based Compensation’’.
Revenue Recognition
Oil, NGLs and natural gas revenues are recognized when production is sold to a purchaser at a
fixed or determinable price, when delivery has occurred and title has transferred and collection of the
revenues is reasonably assured. Cash received relating to future revenues is deferred and recognized
when all revenue recognition criteria are met.
The Company follows the sales method of accounting for oil, NGLs and gas revenues, whereby
revenue is recognized for all oil, NGLs and gas sold to purchasers regardless of whether the sales are
F-23
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
4. Summary of Significant Accounting Policies (Continued)
proportionate to the Company’s ownership interest in the property. Production imbalances are
recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share
of remaining proved oil and gas reserves. The Company had no significant imbalances at December 31,
2016, 2015 or 2014.
Acquisition and Transaction Costs
Acquisition and transaction related costs are expensed as incurred and as services are received.
Such costs include finders’ fees, advisory, legal, accounting, valuation and other professional and
consulting fees, and acquisition related general and administrative costs. Costs incurred in 2015 and
2014 relate to the Dequincy Divestiture and the Pine Prairie Disposition, respectively. See ‘‘—Note 8.
Acquisition and Divestitures of Oil and Gas Properties’’.
Income Taxes
Income taxes are recorded for the tax effects of transactions reported in the financial statements
and consist of taxes currently payable plus deferred income taxes related to certain income and
expenses recognized in different periods for financial and income tax reporting purposes. Deferred
income tax assets and liabilities represent the future tax return consequences of those differences,
which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred
income taxes also include tax credits and net operating losses that are available to offset future income
taxes. Deferred income taxes are measured by applying currently enacted tax rates.
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be
taken in a tax return. Only tax positions that meet the more-than-likely-than-not recognition threshold
are recognized.
Earnings (Loss) Per Share
Basic earnings (loss) per common share is calculated utilizing the two-class method by dividing net
income (loss) available to common shareholders by the weighted average number of common shares
outstanding during each period. Diluted earnings (loss) per common share is calculated under the
two-class method and the treasury stock method by dividing net income (loss) available to common
shareholders by the weighted average number of diluted common shares outstanding, which includes
the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per
share calculations consist of unvested restricted stock awards, warrants and outstanding stock options
for the Successor Period. Potentially dilutive securities for the diluted earnings per share calculations
consist of the Company’s Series A Preferred Stock using the if-converted method (in periods prior to
the Preferred Stock’s mandatory conversion date) and unvested restricted stock awards for the
Predecessor Period. When a loss from continuing operations exists, all potentially dilutive securities are
anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See
‘‘—Note 14. Earnings (Loss) Per Share.’’
Recent Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update 2014-09, ‘‘Revenue from Contracts
with Customers (Topic 606)’’ (‘‘ASU 2014-09’’). ASU 2014-09 provides guidance concerning the
recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09
F-24
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
4. Summary of Significant Accounting Policies (Continued)
is to increase the usefulness of information in the financial statements regarding the nature, timing and
uncertainty of revenues. ASU 2014-09 requires an entity to perform the following steps:
Step 1— Identify the contract with a customer: A contract between two or more parties creates
enforceable rights and obligations. A contract that identifies the relevant parties and has been
approved by those parties, identifies the payment terms, has commercial substance and results in a
probable collection of future consideration meets the definition of ASU 2014-09.
Step 2—Identify the performance obligations in the contract: A performance obligation is
effectively a promise in a contract with a customer to transfer goods or services to the customer. If
an entity promises to transfer more than one good or service to the customer, each performance
obligation is accounted for separately if such performance obligations are distinct, as defined under
ASU 2014-09.
Step 3—Determine the transaction price: The amount of consideration an entity expects to be
entitled to as a result of performing services to a customer or transferring goods to a customer is
the transaction price. The transaction price takes into account variable consideration, the existence
of significant financing component, noncash consideration and the type of consideration payable to
the entity.
Step 4—Allocate the transaction price to the performance obligations in the contract: An entity
should allocate the transaction price to each performance obligation in an amount that represents
the amount of the entity expects to be entitled to for satisfying each performance obligation.
Step 5—Recognize revenue when, or as, the entity satisfies a performance obligation: An entity
recognizes revenue when, or as, it satisfies a performance obligation. A performance obligation can
be satisfied over time or at a point in time. ASU 2014-09 provides criteria for determining the
appropriate classification of each performance obligation.
Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue
recognition guidance in Topic 606, including ASU No. 2015-14, ‘‘Revenue from Contracts with Customers
(Topic 606): Deferral of the Effective Date’’ ASU No. 2016-08, ‘‘Revenue from Contracts with Customers
(Topic 606): Principal versus Agent Considerations’’, ASU No. 2016-10, ‘‘Revenue from Contracts with
Customers (Topic 606): Identifying Performance Obligations and Licensing’’, ASU No. 2016-12, ‘‘Revenue
from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients’’ and
ASU No. 2016-20, ‘‘Technical Corrections and Improvements to Topic 606, Revenue from Contracts with
Customers’’. ASU 2014-09 and the associated amendments mentioned above will be effective for the
Company beginning on January 1, 2018, including interim periods within that reporting period.
The standard permits the use of either the retrospective or cumulative effect transition method
and early adoption is permitted. Currently, the Company has identified the population of contracts and
formed an implementation team to determine the Company’s implementation timelines, discuss
implementation challenges, technical interpretations, industry-specific treatment of certain revenue
contract types, and project status. The Company plans to review contracts for each revenue stream
identified within the Company’s business. Through this process, the Company will determine and
document the expected changes in revenue recognition upon adoption of the revised guidance and then
evaluate the potential information technology and internal control changes that will be required for
adoption based on the findings from the Company’s contract review process. The Company will conduct
the contract review process throughout 2017 and, as a result, areas of impact may be identified. The
F-25
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
4. Summary of Significant Accounting Policies (Continued)
Company cannot reasonably quantify the impact of adoption at this time. The Company expects to
complete the assessment of ASU 2014-09, including the transition method, in the latter half of 2017.
In August 2014, the FASB issued Accountings Standards Update 2014-15, ‘‘Presentation of Financial
Statements—Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity’s Ability to
Continue as a Going Concern’’ (‘‘ASU 2014-15’’). ASU 2014-15 provides guidance about management’s
responsibility to evaluate whether there are conditions or events, considered in the aggregate, that raise
substantial doubt about the entity’s ability to continue as a going concern within one year after the date
that the financial statements are issued. Certain disclosures are required should substantial doubt exist
about the entities ability to continue as a going concern. This evaluation is performed each annual and
interim reporting period to assess conditions or events within one year of the date that the financial
statements are issued. The new standard was adopted by the Company at December 31, 2016.
In February 2016, the FASB issued Accounting Standards Update 2016-02, ‘‘Leases (Topic 842)’’
(‘‘ASU 2016-02’’). ASU 2016-02 establishes a right-of-use (‘‘ROU’’) model that requires a lessee to
record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than
12 months. All leases create an asset and a liability for the lessee and therefore recognition of those
lease assets and lease liabilities is required by ASU 2016-02. When measuring lease assets and
liabilities, payments to be made in optional extension periods should be included if the lessee is
reasonably certain to exercise the option. Leases will be classified as either finance or operating, with
classification affecting the pattern of expense recognition in the income statement.
For finance leases, the Company will recognize a ROU asset and liability, initially measured at the
present value of the lease payments. Interest expense will be recognized on the lease liability separately
from the amortization of the ROU asset. The Company will recognize payments of principal on the
lease liability within financing activities in the consolidated statement of cash flows and payments of
interest within operating activities in the consolidated statement of cash flows. For operating leases, the
Company will recognize a ROU asset and liability, initially measured at the present value of the lease
payments. The Company will recognize a single lease cost, calculated so that the cost of the lease is
allocated over the lease term on a generally straight-line basis and all cash payments will be recognized
in operating activities within the consolidate statement of cash flows.
The new standard is effective for fiscal years beginning after December 15, 2018, including interim
periods within those fiscal years. A modified retrospective transition approach is required for lessees
for capital and operating leases existing at, or entered into after, the beginning of the earliest
comparative period presented in the financial statements, with certain practical expedients available.
The Company is in the initial evaluation and planning stages for ASU 2016-02 and does not expect to
move beyond this stage until completion of its evaluation of ASU 2014-09, which is expected to occur
in the latter half of 2017.
In March 2016, the FASB issued ASU 2016-09, ‘‘Compensation—Stock Compensation (Topic 718)’’
(‘‘ASU 2016-09’’). ASU 2016-09 simplifies how certain aspects of share-based payments to employees
are recorded. ASU 2016-09 requires that entities recognize the income tax effects of awards in the
income statement when the awards vest or are settled, provides guidance on the classification of certain
aspects of share-based payments on the statement of cash flows, changes the threshold for awards to
qualify for equity classification, and allows an entity to make an accounting policy election to account
for forfeitures when they occur. The new standard is effective for the Company beginning on January 1,
F-26
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
4. Summary of Significant Accounting Policies (Continued)
2017. As of December 31, 2016, the Company elected to early adopt the pronouncement and it did not
have a material impact on its financial results.
In August 2016, the FASB issued ASU 2016-15, ‘‘Statement of Cash Flows—Classification of Certain
Cash Receipts and Cash Payments’’ (‘‘ASU 2016-15’’). ASU 2016-15 addresses eight specific cash flow
issues with the objective of reducing existing diversity of practice. The eight specific cash flow issues
contained within ASU 2016-15 are debt prepayment or debt extinguishment costs, settlement of
zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant
in relation to the effective interest rate of the borrowing, contingent consideration payments made after
a business combination, proceeds from the settlement of insurance claims, proceeds from the
settlement of corporate-owned life insurance policies, distributions received from equity method
investees, beneficial interests in securitization transactions and separately identifiable cash flows and
application of the predominance principle. ASU 2016-15 is effective for the Company for fiscal years
beginning after December 15, 2017, and interim periods within those fiscal years. The Company does
not believe the adoption of ASU 2016-15 will have a material impact on its cash flows.
5. Fair Value Measurements of Financial Instruments
The Company uses a valuation framework based upon inputs that market participants use in
pricing an asset or liability, which are classified into two categories: observable inputs and unobservable
inputs. Observable inputs represent market data obtained from independent sources; whereas,
unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs
are not reasonably available without undue cost and effort. These two types of inputs are further
divided into the following fair value input hierarchy:
(cid:127) Level 1—Inputs are unadjusted quoted prices in active markets for identical assets or liabilities
at the measurement date.
(cid:127) Level 2—Inputs, other than quoted prices included in Level 1, are observable for the asset or
liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments
in active markets, and inputs other than quoted prices that are observable for the asset or
liability. Fair value assets and liabilities that are generally included in this category are
commodity derivative contracts with fair values based on inputs from actively quoted markets.
The Company uses a discounted cash flow approach to estimate the fair values of its commodity
derivative contracts, utilizing commodity futures price strips for the underlying commodities
provided by a reputable third-party.
(cid:127) Level 3—Inputs are unobservable for the asset or liability, and include situations where there is
little, if any, market activity for the asset or liability.
Assets and liabilities are classified based on the lowest level of input that is significant to the fair
value measurement. The Company’s assessment of the significance of a particular input to the fair
value measurement requires judgment, and may affect the valuation of the fair value of assets and
liabilities and their placement within the fair value hierarchy levels.
F-27
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
6. Risk Management and Derivative Instruments
The Company’s production is exposed to fluctuations in crude oil, NGLs and natural gas prices.
The Company believes it is prudent to manage the variability in cash flows by, at times, entering into
derivative financial instruments to economically hedge a portion of its crude oil, NGLs and natural gas
production. The Company has historically utilized various types of derivative financial instruments,
including swaps and collars, to manage fluctuations in cash flows resulting from changes in commodity
prices. These derivative contracts are placed with major financial institutions that the Company believes
are minimal credit risks. The oil, NGLs and gas reference prices, upon which the commodity derivative
contracts are based, reflect various market indices that management believes have a high degree of
historical correlation with actual prices received by the Company for its oil, NGLs and natural gas
production. Although the Company has entered into derivative financial instruments in the past, the
Company had no derivatives in place at December 31, 2016.
Subsequent to December 31, 2016, the Company entered into various oil and natural gas derivative
contracts that extend through March 2018, summarized as follows:
Quarter Ended Quarter Ended
June 30, 2017
March 31, 2017
Quarter Ended
Quarter Ended
September 30, 2017 December 31, 2017 March 31, 2018
Quarter Ended
NYMEX WTI
Fixed swaps
Hedge position (Bbls) . . . . . . . .
Weighted average strike price . . . $
105,500
55.17 $
Collars
Hedge position (Bbls) . . . . . . . .
Weighted average ceiling price . . . $
Weighted average floor price . . . . $
74,500
59.68 $
50.00 $
Three way collars
Hedge position (Bbls) . . . . . . . .
Weighted average ceiling price . . . $
Weighted average floor price . . . . $
Weighted average sub-floor price . $
NYMEX HENRY HUB
Fixed swaps
—
— $
— $
— $
227,500
55.12 $
136,500
59.73 $
50.00 $
—
— $
— $
— $
207,000
55.29 $
46,000
60.00 $
50.00 $
115,000
62.80 $
50.00 $
40.00 $
207,000
55.29 $
46,000
60.00 $
50.00 $
115,000
62.80 $
50.00 $
40.00 $
Hedge position (MMBtu) . . . . . .
Weighted average strike price . . . $
—
— $
2,912,000
3.38 $
2,944,000
3.38 $
992,000
3.38 $
Collars
Hedge position (MMBtu) . . . . . .
Weighted average ceiling price . . . $
Weighted average floor price . . . . $
1,298,000
3.70 $
3.10 $
Three way collars
Hedge position (MMBtu) . . . . . .
Weighted average ceiling price . . . $
Weighted average floor price . . . . $
Weighted average sub-floor price . $
—
— $
— $
— $
—
— $
— $
—
— $
— $
— $
—
— $
— $
—
— $
— $
— $
—
— $
— $
610,000
4.30 $
3.25 $
2.50 $
—
—
—
—
—
135,000
63.50
50.00
40.00
—
—
—
—
—
900,000
4.30
3.25
2.50
Commodity Derivative Contracts
As of December 31, 2016 and 2015, the Company did not have any open commodity derivative
contract positions.
Gains/Losses on Commodity Derivative Contracts
The Company does not designate its commodity derivative contracts as hedging instruments for
financial reporting purposes. Accordingly, commodity derivative contracts were marked-to-market each
quarter with the change in fair value during the periodic reporting period recognized currently as a
F-28
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
6. Risk Management and Derivative Instruments (Continued)
gain or loss in ‘‘Gains (losses) on commodity derivative contracts—net’’ within revenues in the
consolidated statements of operations.
The following table presents net cash received (paid) for commodity derivative contracts and
unrealized net gains (losses) recorded by the Company related to the change in fair value of the
derivative instruments in ‘‘Gains (losses) on commodity derivative contracts—net’’ for the periods
presented (in thousands):
Successor
Predecessor
For the Period
October 21, 2016
through
For the Period
January 1, 2016
through
For the Years Ended
December 31,
December 31, 2016 October 20, 2016
2015
2014
Net cash received (paid) for commodity
derivative contracts . . . . . . . . . . . . . . . . . . .
Unrealized net gains (losses) . . . . . . . . . . . . . .
Gains on commodity derivative contracts—net .
$
$
— $
—
— $
— $ 167,669
— (126,709)
$ (18,332)
157,521
— $ 40,960
$139,189
Cash settlements, as presented in the table above, represent realized gains related to the
Company’s derivative instruments. In addition to cash settlements, the Company also recognizes fair
value changes on its derivative instruments in each reporting period. The changes in fair value result
from new positions and settlements that may occur during each reporting period, as well as the
relationships between contract prices and the associated forward curves.
7. Property and Equipment
The Company’s property and equipment as of December 31, 2016 and 2015 was as follows (in
thousands):
Oil and gas properties, on the basis of full-cost
accounting:
Proved properties . . . . . . . . . . . . . . . . . . . . . .
Unproved properties not being amortized . . . . .
. . . . . . . . . . . . . .
Other property and equipment
Less accumulated depreciation, depletion,
Successor
Predecessor
December 31, 2016 December 31, 2015
$
$
573,150
65,080
6,339
3,666,403
—
14,798
amortization and impairment . . . . . . . . . . . .
(12,974)
(3,157,332)
Net property and equipment . . . . . . . . . . . . . . . .
$
631,595
$
523,869
For the Successor Period and the Predecessor Period, depletion expense related to oil and gas
properties was $12.6 million and $59.9 million, respectively and $7.00 and $6.84, per barrel of oil
equivalent (‘‘Boe’’), respectively. For the years ended December 31, 2015 and 2014, depletion expense
related to oil and gas properties was $195.2 million and $266.8 million, respectively and $16.26 and
$22.75 per Boe, respectively. For the Successor Period, Predecessor Period and the years ended
December 31, 2015 and 2014, depreciation expense related to other property and equipment was
$0.4 million, $2.4 million, $3.5 million and $3.1 million, respectively.
F-29
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
7. Property and Equipment (Continued)
For the Successor Period and the years ended December 31, 2015 and 2014, interest capitalized to
unevaluated properties was $0.7 million, $4.9 million and $12.4 million, respectively. The Company did
not capitalized interest for the Predecessor Period. For the Successor Period, Predecessor Period and
the years ended December 31, 2015 and 2014, the Company capitalized $1.4 million, $3.4 million,
$7.3 million and $12.4 million, respectively, of internal costs to oil and gas properties, including
$0.6 million, $0.5 million, $1.3 million and $2.2 million, respectively, of qualifying share based
compensation expense, see ‘‘—Note 12. Equity and Share Based Compensation’’.
8. Acquisition and Divestitures of Oil and Gas Properties
Dequincy Divestiture
On April 21, 2015, the Company closed the Dequincy Divestiture for $44.0 million, completing the
Company’s disposition of its producing properties and proved reserves in Louisiana. The net proceeds,
inclusive of amounts placed in escrow, were approximately $42.4 million, which was net of customary
closing adjustments. This amount was reflected as a reduction of oil and natural gas properties, with no
gain or loss recognized. The net proceeds were retained for general corporate purposes.
Pine Prairie Disposition
On May 1, 2014, the Company closed on the sale of all of its ownership interest in developed and
undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer
for a purchase price of $170.0 million in cash ($147.7 million net of standard post-closing adjustments).
Acreage subject to the transaction did not include acreage and production in the western part of
Louisiana in Beauregard and Calcasieu Parishes or other undeveloped acreage held outside the Pine
Prairie field. Proceeds of $131.0 million were used to reduce amounts outstanding under the RBL, with
the remainder retained for transaction expenses and working capital purposes. This amount was
reflected as a reduction of oil and natural gas properties, with no gain or loss was recognized.
Exploration Agreement with PetroQuest
On June 25, 2014, the Company entered into an exploration agreement with PetroQuest
Energy LLC (‘‘PetroQuest’’) with an effective date of May 1, 2014, in which the Company conveyed to
PetroQuest an undivided 50% of its right, title and interest in and to the acreage and other interests in
the Fleetwood prospect area in Louisiana. With the execution of the agreement, PetroQuest paid
$3.0 million in cash consideration and in January 2015, PetroQuest paid additional cash of $7.0 million.
As further consideration, PetroQuest granted a credit to the Company of an additional non-interest
bearing total sum of $14.0 million, to be credited or paid against the Company’s share of costs or
expenses incurred to develop the prospect area, including but not limited to, all mineral lease
acquisition or maintenance costs and all drilling, completion, equipping and facility costs. For any
amounts not fully credited on or before December 31, 2015, the Company could elect to take the
remaining portion in cash. The Company received the unutilized portion of the non-interest bearing
amount of approximately $4.4 million during 2016.
Acquisition and Transaction Expenses
For the year ended December 31, 2015, acquisition and transaction costs of $0.3 million relate to
the execution of the Dequincy Divestiture.
F-30
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
8. Acquisition and Divestitures of Oil and Gas Properties (Continued)
For the year ended December 31, 2014, acquisition and transaction costs of $4.1 million were
incurred primarily as a result of the Pine Prairie Disposition and include advisory, legal, accounting,
valuation and other professional and consulting fees related to the sale.
9. Asset Retirement Obligations
For the Company, asset retirement obligations (‘‘AROs’’) represent the future abandonment costs
of tangible assets, such as wells, service assets and other facilities. The fair value of the asset retirement
obligation at inception is capitalized as part of the carrying amount of the related long-lived asset.
Asset retirement obligations approximated $14.2 million and $18.7 million as of December 31, 2016 and
2015, respectively. At December 31, 2016 and 2015, all asset retirement obligations represent long-term
liabilities and are classified as such.
The following table details the change in the asset retirement obligations for the Successor Period
and the years ended December 31, 2015 and 2014, respectively (in thousands):
Successor
Predecessor
For the Period
October 21, 2016
through
December 31, 2016
For the Years Ended
December 31,
2015
2014
Asset retirement obligations at beginning of
period . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities incurred . . . . . . . . . . . . . . . . . . . . . .
Revisions(1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled . . . . . . . . . . . . . . . . . . . . . . .
Liabilities eliminated through asset sale(2) . . . . .
Current period accretion expense . . . . . . . . . . .
$
13,983 $21,599
127
7
—
570
— (279)
— (4,919)
1,610
210
$26,308
996
288
(47)
(7,652)
1,706
Asset retirement obligations at end of year . . . .
$
14,200 $18,708
$21,599
(1) Revisions during the year ended December 31, 2015 were the result of updates to the
estimated abandonment dates of various wells. Revisions during the year ended
December 31, 2014 were due primarily to an increase in estimated future abandonment
costs based upon higher costs for oilfield services and materials in the Mississippian Lime
and Anadarko Basin areas.
(2) Liabilities eliminated through asset sales for the year ended December 31, 2015 is
primarily related to the Dequincy Divestiture. Liabilities eliminated through asset sales
for the year ended December 31, 2014 were related to the Pine Prairie Disposition. See
discussion of the Dequincy Divestiture and Pine Prairie Disposition in
‘‘—Note 8. Acquisition and Divestitures of Oil and Gas Properties’’.
F-31
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
10. Debt
The Company’s total debt, including debt classified as current, as of December 31, 2016 and 2015
is as follows (in thousands):
Principal
Unamortized Deferred
Gain on Debt Forgiven
Unamortized Debt
Issuance Costs
Total
Successor Predecessor Successor Predecessor Successor Predecessor Successor Predecessor
2016
2015
2016
2015
2016(1)
2015
2016
2015
Predecessor Credit Facility . $
Successor Exit Facility . . . .
2020 Senior Notes . . . . . . .
2021 Senior Notes . . . . . . .
Second Lien Notes . . . . . .
Third Lien Notes . . . . . . .
— $
128,059
—
—
—
—
— $
—
293,625
347,652
625,000
529,653
— $
—
—
—
—
—
— $
—
—
—
42,293
77,361
— $
—
—
—
—
—
— $
— $
— 128,059
—
—
—
—
(11,344)
(13,296)
—
—
—
—
282,281
334,356
667,293
607,014
Total debt . . . . . . . . . . . . $ 128,059 $ 1,795,930 $
— $
119,654 $
— $
(24,640) $ 128,059 $ 1,890,944
(1) Unamortized debt issuance costs of $1.2 million associated with the Exit Facility are included in other noncurrent
assets on the consolidated balance sheets.
2016 Reorganization
On the Effective Date, the Company satisfied the conditions to effectiveness set forth in the
Confirmation Order and in the Plan, and, as a result, the Plan became effective in accordance with its
terms and the Company emerged from the Chapter 11 Cases. Pursuant to the confirmed Plan, the
significant transactions impacting the Company’s outstanding debt balances as of the Effective Date
were as follows:
(cid:127) Credit Facility: (i) The permanent pay-down of $81.3 million of the Company’s RBL with a
$170.0 million Exit Facility established upon the Effective Date, (ii) the pay-down of
$60.0 million of our Second Lien Notes in cash, and (iii) the conversion into equity of all of the
Company’s remaining debt junior to the RBL;
(cid:127) Credit Facility Claims: Holders of allowed claims arising under the RBL (the ‘‘Credit Facility
Claims’’) received their pro rata share of approximately $81.3 million in cash and the RBL was
superseded, pursuant to the Plan, by the Exit Facility, as further described below;
(cid:127) Second Lien Notes Claims: Holders of allowed claims arising under the Second Lien Notes (the
‘‘Second Lien Notes Claims’’) received their pro rata share of (i) 96.25% of the reorganized
equity in the form of common stock and (ii) a cash payment of $60.0 million;
(cid:127) Third Lien Notes Claims: Holders of Third Lien Notes Claims, pursuant to the Second/Third
Lien Plan Settlement, received their pro rata share of 2.5% of the reorganized equity in the
form of common stock and warrants to acquire 4,411,765 shares of common stock at a strike
price of $24.00 per common share with an expiration date 42 months after the Effective Date;
(cid:127) Unsecured Claims: Unsecured Notes Claims and the Holders of other general unsecured claims
received their pro rata share of 1.25% of reorganized equity in the form of common stock and
warrants to acquire 2,213,789 shares of common stock at a strike price of $46.00 per common
share with an expiration date 42 months after the Effective Date; and
F-32
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
10. Debt (Continued)
(cid:127) Exit Facility: The Company’s RBL, which was redetermined with a borrowing base of
$170.0 million in April 2016, was superseded, pursuant to the Plan, by the Exit Facility as further
described below.
2015 Debt Restructuring
On May 21, 2015, the Company issued $625.0 million of Second Lien Notes and utilized the
proceeds to repay the outstanding balance of the RBL in an amount of approximately $468.2 million,
with the remainder utilized for general corporate purposes. Further, the Company exchanged
approximately $504.1 million of Third Lien Notes for approximately $279.8 million of 2020 Senior
Notes and $350.3 million of 2021 Senior Notes, representing an exchange at 80.0% of the exchanged
Unsecured Notes’ par value. Additionally, on June 2, 2015, the Company exchanged approximately
$20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and
$2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Unsecured
Notes’ par value. Approximately $63.9 million of the principal amount of 2020 Senior Notes and
$70.7 million of the principal amount of 2021 Senior Notes was extinguished.
The exchanges of Third Lien Notes for the Unsecured Notes as well as the issuance of the Second
Lien Notes were accounted for as a troubled debt restructuring. As the future cash flows of the
modified debt instruments were greater than the carrying amount of the previous debt instruments, no
debt extinguishment gain was recognized. The amount of extinguished debt was to be amortized over
the remaining life of the Second Lien Notes and Third Lien Notes using the effective interest method
and recognized as a reduction of interest expense. All costs incurred related to the May 21, 2015 and
June 2, 2015 exchanges, including restructuring costs as well as the direct issuance costs of the Second
Lien Notes and Third Lien Notes, were expensed and are included within debt restructuring costs and
advisory fees in the consolidated statements of operations. As a result of the Company’s emergence on
the Effective Date, the remaining unamortized gain on the troubled debt restructuring was eliminated
at that time.
Exit Facility
At December 31, 2016, the Company maintained the Exit Facility with a borrowing base of
$170.0 million with no borrowing base redeterminations to occur until April 2018 (provided certain
conditions are met) and semiannual borrowing base redeterminations each year on April 1 and
October 1 thereafter. Until April 2018, unless the borrowing base is redetermined earlier, the amount
available to be drawn under the Exit Facility is reduced by $40.0 million, and thereafter, the Company
must maintain liquidity (as defined therein) equal to at least 20.0% of the effective borrowing base. At
December 31, 2016, the Company had $128.1 million drawn on the Exit Facility and had outstanding
letters of credit obligations totaling $1.9 million. As a result, at December 31, 2016 the Company had
no amount of availability on the Exit Facility.
The Exit Facility matures on September 30, 2020 and borrowings thereunder are secured by
(i) first-priority mortgages on at least 95% of the Company’s oil and gas properties, (ii) all other
presently owned or after-acquired property (including but not limited to as-extracted collateral,
accounts receivable, inventory, equipment, general intangibles, investment property, intellectual
property, real property and the proceeds of the foregoing) and (iii) a perfected pledge on all equity
F-33
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
10. Debt (Continued)
interests. The Exit Facility bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR
floor. At December 31, 2016, the weighted average interest rate was 5.50%.
In addition to interest expense, the Exit Facility requires the payment of a commitment fee each
quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily
amount by which the borrowing base exceeds the outstanding borrowings during each quarter.
In addition to the aforementioned liquidity covenant, the Exit Facility, also contains various other
financial covenants, including an EBITDA to interest expense coverage ratio limitation of 3.00:1.00, a
ratio limitation of Total Net Indebtedness (as defined in the Exit Facility) to EBITDA of not more than
2.25:1.00 through April 1, 2018 and not more than 3.00:1.00 thereafter, and a limitation on Capital
Expenditures (as defined) of $50.0 million for the 6 months ended December 31, 2016, $81.0 million
for the year ended December 31, 2017, $85.0 million for the year ended December 31, 2018 and
$78.0 million for the year ended December 31, 2019. The Exit Facility is also subject to a variety of
other terms and conditions including conditions precedent to funding, restrictions on the payment of
dividends and various other covenants and representations and warranties. As of December 31, 2016,
the Company was in compliance with our debt covenants.
The Company believes the carrying amount of the Credit Facility at December 31, 2016
approximates its fair value (Level 2) due to the variable nature of the Exit Facility interest rate.
RBL
Prior to the Effective Date, the Company maintained the $750.0 million RBL with a borrowing
base of $252.0 million. In February 2016, the Company borrowed approximately $249.2 million under
the RBL, which represented the remaining undrawn availability. As a result of the semiannual
redetermination on April 1, 2016, the borrowing base was reduced by $82.0 million to $170.0 million
from the previous borrowing base of $252.0 million.
Borrowing under the RBL bore interest at LIBOR plus an applicable margin, depending upon the
Company’s borrowing base utilization, between 2.00% and 3.00% per annum. In addition to interest
expense, the RBL required the payment of a commitment fee each quarter at the rate of either 0.375%
or 0.500% per annum based on the average daily amount by which the borrowing base exceeded the
outstanding borrowings during each quarter.
The RBL was superseded and replaced by the Exit Facility on the Effective Date. On the Effective
Date, $121.3 million of outstanding borrowings on the RBL were repaid, with the remaining
outstanding balance carried over to the Exit Facility.
2020 Senior Notes
On October 1, 2012, the Company issued $600.0 million in aggregate principal amount of 2020
Senior Notes, conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as
amended (the ‘‘Securities Act’’). In October 2013, these notes were exchanged for an equal principal
amount of identical registered notes. On May 21, 2015 and June 2, 2015, a total of approximately
$306.4 million aggregate principal amount of 2020 Senior Notes were exchanged for Third Lien Notes.
The 2020 Senior Notes had an interest rate of 10.75%.
F-34
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
10. Debt (Continued)
On the Effective Date, the obligations of the Company with respect to the 2020 Senior Notes were
cancelled and holders of the 2020 Senior Notes received their agreed upon pro-rata share of the
Unencumbered Assets Equity Distribution. See ‘‘—Note 2. Emergence from Voluntary Reorganization
under Chapter 11 Proceedings’’ for further discussion.
2021 Senior Notes
On May 31, 2013, the Company issued $700.0 million in aggregate principal amount of 2021 Senior
Notes. In October 2013, these notes were exchanged for an equal principal amount of identical
registered notes. On May 21, 2015 and June 2, 2015, a total of approximately $352.3 million aggregate
principal amount of 2021 Senior Notes were exchanged for Third Lien Notes. The 2021 Senior Notes
had an interest rate of 9.25%.
On the Effective Date, the obligations of the Company with respect to the 2021 Senior Notes were
cancelled and holders of the 2021 Senior Notes received their agreed-upon pro-rata share of the
Unencumbered Assets Equity Distribution. See ‘‘—Note 2. Emergence from Voluntary Reorganization
under Chapter 11 Proceedings’’ for further discussion.
Second Lien Notes
On May 21, 2015, the Company and Midstates Sub issued and sold $625.0 million aggregate
principal amount of Second Lien Notes, in a private placement conducted pursuant to Rule 144A
under the Securities Act. In November 2015, these notes were exchanged for an equal principal amount
of identical registered notes. The Second Lien Notes had an interest rate of 10.0%.
On the Effective Date, the obligations of the Company with respect to the Second Lien Notes
were cancelled and holders of the Second Lien Notes received a cash payment of $60.0 million as well
as their agreed-upon pro-rata share of equity in the reorganized Company. See ‘‘—Note 2. Emergence
from Voluntary Reorganization under Chapter 11 Proceedings’’ for further discussion.
Third Lien Notes
On May 21, 2015 and June 2, 2015, the Company issued approximately $504.1 million and
$20.0 million, respectively, in aggregate principal amount of Third Lien Notes in a private placement
and in exchange for an aggregate $306.4 million of the 2020 Senior Notes and $352.3 million of the
2021 Senior Notes. In November 2015, these notes were exchanged for an equal principal amount of
identical registered notes. The Third Lien Notes had an interest rate of 12.0%, consisting of cash
interest of 10.0% and paid-in-kind interest of 2.0%, per annum.
On the Effective Date, the obligations of the Company with respect to the Third Lien Notes were
cancelled and holders of the Third Lien Notes received their agreed upon pro-rata share of equity and
warrants in the reorganized Company as set forth in the Second/Third Lien Plan Settlement embodied
in the Plan. See ‘‘—Note 2. Emergence from Voluntary Reorganization under Chapter 11 Proceedings’’
for further discussion.
F-35
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
11. Preferred Stock
Series A Preferred Stock
On October 1, 2012, the Company issued 325,000 shares of Series A Mandatorily Convertible
Preferred Stock (‘‘Series A Preferred Stock’’) with an initial liquidation preference of $1,000 per share
and an 8.0% per annum dividend, payable semiannually at the Company’s option in cash or through an
increase in the liquidation preference. Based on the liquidation preference at September 30, 2015, each
Series A Preferred Share converted into approximately 11.5 shares of the Company’s Predecessor
common stock pursuant to the Certificate of Designation, which governed the Series A Preferred Stock.
As a result, the Company issued 3,738,424 shares of Predecessor common stock upon conversion of the
Series A Preferred Stock during 2015.
At the Effective Date, the Company’s current common stock was cancelled and new common stock
of the reorganized Company was issued. See ‘‘—Note 2. Emergence from Voluntary Reorganization
under Chapter 11 Proceedings’’ for further discussion.
12. Equity and Share-Based Compensation
Emergence from Bankruptcy
On the Effective Date, the Company’s then existing common stock was canceled and new common
stock in the reorganized Company was issued. In addition, Company’s previous share-based
compensation awards were either vested or canceled upon the Company’s emergence from bankruptcy.
Common Shares
Successor Period
On the Effective Date, the Company issued 24,687,500 shares of Successor common stock in the
reorganized Company. On November 8, 2016, the Company issued 12,400 shares of common stock to
employees and non-employee directors, which vested immediately upon issuance. On November 9,
2016, the Company issued an additional 294,967 shares of common stock of the reorganized Company
pursuant to the Plan. The Company will issue 17,533 additional common shares pursuant to the Plan in
a future distribution. The total authorized common stock of the reorganized Company consists of
250,000,000 shares of common stock and 50,000,000 shares of preferred stock, par value $0.01 per
share. Holders of the Company’s common shares are entitled to one vote for each share held of record
on all matters submitted to a vote of stockholders and to receive ratably in proportion to the shares of
common stock held by them any dividends declared from time to time by the board of directors. The
common shares have no preferences or rights of conversion, exchange, pre-exemption or other
subscription rights.
At December 31, 2016, the Company had 24,994,867 shares of common stock issued and
outstanding.
Predecessor Period
At December 31, 2015, the Company had 10,962,105 and 10,865,814 shares of its common stock
issued and outstanding, respectively.
On August 3, 2015, the Company completed a 1-for-10 reverse stock split of its outstanding
common stock. To effect the reverse stock split, the Company filed a Certificate of Amendment to the
F-36
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
12. Equity and Share-Based Compensation (Continued)
Company’s Restated Certificate of Incorporation, which provides for the reverse stock split and for the
corresponding reduction in the Company’s authorized capital stock to 100 million shares of common
stock, $0.01 par value per share, following the reverse stock split.
Share Activity
The following table summarizes changes in the number of shares of common stock and treasury
stock outstanding since January 1, 2015:
Share count as of December 31, 2014 (Predecessor) . . . . . . . . . . . . . . . . . . . .
Grants of restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeitures of restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fractional share adjustment due to reverse stock split . . . . . . . . . . . . . . . . . . .
Issuance of common stock for Series A Preferred Stock conversion . . . . . . . . .
Common
Stock
Treasury
Stock(1)
7,049,173
268,677
(94,159)
(53,467)
—
—
— (42,824)
—
(10)
—
3,738,424
Share count as of December 31, 2015 (Predecessor) . . . . . . . . . . . . . . . . . . . .
Grants of restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeitures of restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,962,105
—
(47,325)
(96,291)
—
—
— (52,358)
Share count as of October 21, 2016 (Predecessor) . . . . . . . . . . . . . . . . . . . . .
Cancellation of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancellation of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,914,780
(10,914,780)
(148,649)
—
— 148,649
Share count as of October 21, 2016 (Predecessor) . . . . . . . . . . . . . . . . . . . . .
—
Issuance of successor common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24,687,500
Share count as of October 21, 2016 (Successor) . . . . . . . . . . . . . . . . . . . . . . .
Issuance of successor common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24,687,500
307,367
—
Share count as of December 31, 2016 (Successor) . . . . . . . . . . . . . . . . . . . . .
24,994,867
—
—
—
—
—
—
(1) Treasury stock represents the net settlement on vesting of restricted stock necessary to satisfy the
minimum statutory withholding requirements.
Warrants
At the Effective Date, the Company issued 4,411,765 Third Lien Notes Warrants to purchase up to
an aggregate of 4,411,765 shares of common stock at an initial exercise price of $24.00 per share and
2,213,789 Unsecured Creditor Warrants to purchase up to an aggregate of 2,213,789 shares of common
stock at an initial exercise price of $46.00 per share. The Warrants expire on April 21, 2020.
Holders of the Warrants do not have the right to vote, to consent, to receive any cash dividends,
stock dividends, allotments or rights or other distributions paid, allotted or distributed or distributable
to the holders of shares of common stock, or to exercise any rights whatsoever as a stockholder of the
F-37
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
12. Equity and Share-Based Compensation (Continued)
Company unless, until and only to the extent such holder of Warrants becomes a holder of record of
shares of common stock issued upon settlement of Warrants.
The number of shares of common stock for which the Warrants is exercisable, and the exercise
price per share of the Warrants are subject to adjustment from time to time upon the occurrence of
certain events, including the issuance of common stock as a dividend or distribution to all holders of
shares of common stock, a pro rata repurchase offer of common stock or a subdivision, combination,
split, reverse split or reclassification of outstanding common stock into a greater or smaller number of
shares of common stock.
Upon the occurrence of certain events constituting an organic change (as defined in the Warrant
Agreements), holders of the Warrants will have the right to receive, upon exercise of the Warrants, the
amount of securities, cash or other property received in connection with such event with respect to or
in exchange for the number of shares of common stock for which such Warrants are exercisable
immediately prior to such event.
The Warrants permit a holder to elect to exercise the Warrants such that no payment of cash will
be required in connection with such exercise (a ‘‘Net Share Settlement’’). If Net Share Settlement is
elected, the Company is authorized to withhold and not issue in payment of the exercise price, a
number of shares of common stock equal to (i) the number of shares of common stock for which the
Warrants are being exercised, multiplied by (ii) the exercise price, and divided by (iii) the current sale
price (as defined in the Warrant Agreements) on the exercise date.
Share-Based Compensation
Emergence from Bankruptcy
The Company’s share-based compensation awards that remained unvested at the Effective Date
were cancelled upon the Company’s emergence from the Chapter 11 Cases. The cancellation of these
share-based compensation awards resulted in the recognition of $1.3 million of expense in the
Predecessor Period to record any previously unamortized expense related to such awards. Also at the
Effective Date, the Company’s 2012 Long Term Incentive Plan (the ‘‘2012 LTIP’’) was replaced by the
Company’s 2016 LTIP. The types of awards that may be granted under the 2016 LTIP include stock
options, restricted stock units, restricted stock, performance awards and other forms of awards granted
or denominated in shares of common stock of the reorganized Company, as well as certain cash-based
awards (the ‘‘Awards’’). The terms of each award are as determined by the Compensation Committee
of the Board of Directors.
2016 Long Term Incentive Plan
On the Effective Date, the Company established the 2016 LTIP and filed a Form S-8 with the
SEC, registering 3,513,950 shares for issuance under the terms of the 2016 LTIP to employees,
directors and certain other persons (the ‘‘Award Shares’’).
Subject to certain limitations as defined in the 2016 LTIP, the terms of each Award are to be
determined by the Compensation Committee of the Board of Directors. Awards that expire, or are
canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future
issuance under the 2016 LTIP. At December 31, 2016, 2,111,786 Award Shares remain available for
issuance under the terms of the 2016 LTIP.
F-38
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
12. Equity and Share-Based Compensation (Continued)
2012 Long Term Incentive Plan
On April 20, 2012, the Company established the 2012 LTIP and filed a Form S-8 with the SEC.
The 2012 LTIP provided for the granting of Options (Incentive and other), Restricted Stock Awards,
Restricted Stock Units, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other
Stock-Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the
foregoing. Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award were
determined by the Compensation Committee of the Board of Directors. The 2012 LTIP was cancelled
upon the Company’s emergence on the Effective Date.
Restricted Stock Units
As of December 31, 2016, the Company had 685,662 shares of restricted stock units outstanding to
employees and non-employee directors pursuant to the 2016 LTIP, excluding restricted stock units
issued to non-employee directors containing a market condition, which are discussed below. Restricted
stock units granted to employees under the 2016 LTIP vest ratably over a period of three years:
one-sixth will vest on the six-month anniversary of the Effective Date, an additional one-sixth will vest
on the twelve-month anniversary of the Effective Date, an additional one-third will vest on the
twenty-four month anniversary of the Effective Date and the final one-third will vest on the thirty-six
month anniversary of the Effective Date. Restricted stock units granted to non-employee directors vest
on the first to occur of (i) December 31, 2017, (ii) the date the non-employee director ceases to be a
director of the Board (other than for cause), (iii) the director’s death, (iv) the director’s disability or
(v) a change in control of the Company.
If an employee terminates employment prior to the vesting date, the outstanding award is
forfeited. Restricted stock units are subject to accelerated vesting in the event a recipient’s employment
is terminated prior to the vesting date by the Company without ‘‘Cause’’ or by the participant with
‘‘Good Reason’’ (each, as defined in the 2016 LTIP) or due to the participant’s death or disability.
The fair value of restricted stock units was based on grant date fair value of the Company’s
common stock. Compensation expense is recognized ratably over the requisite service period.
F-39
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
12. Equity and Share-Based Compensation (Continued)
The following table summarizes the Company’s non-vested restricted stock unit award activity for
the years ended December 31, 2016, 2015 and 2014:
Restricted Stock
Weighted Average
Grant Date
Fair Value
Non-vested shares outstanding at December 31, 2014 (Predecessor) . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested shares outstanding at December 31, 2015 (Predecessor) . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested shares outstanding at October 20, 2016 (Predecessor) . . . .
Cancellation of non-vested shares . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested shares outstanding at October 20, 2016 (Predecessor) . . . .
Granted at Effective Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested shares outstanding at October 21, 2016 (Successor) . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested shares outstanding at December 31, 2016 (Successor) . . . .
$
306,202
$
268,677
(162,689) $
(94,159) $
318,031
$
— $
(162,393) $
(47,325) $
108,313
$
(108,313) $
— $
686,324
$
$
686,324
2,035
$
(2,697) $
685,662
$
52.76
12.29
54.39
38.69
21.46
—
23.09
19.02
20.08
20.08
—
19.66
19.66
20.97
19.66
19.66
On December 31, 2016, the Company elected to early adopt ASU 2016-09 and chose to recognize
the effect of awards for which the requisite service is not rendered when the actual award is forfeited.
Previously, the Company estimated the forfeiture rate and applied it ratably to expense over the vesting
period, recognizing any differences between estimated forfeitures and actual forfeitures at the end of
the period.
The share-based compensation costs (net of amounts capitalized to oil and gas properties) related
to restricted stock units recognized as general and administrative expense by the Company for the
Successor Period, Predecessor Period and the years ended December 31, 2015 and 2014, was
$1.7 million, $2.6 million, $4.4 million, and $8.6 million, respectively. For the Successor Period,
Predecessor Period and the years ended December 31, 2015 and 2014, the Company capitalized
$0.4 million, $0.5 million, $1.3 million and $2.2 million, respectively, of qualifying restricted stock unit
share-based compensation costs to oil and gas properties.
For the year ended December 31, 2014, the Company announced that its corporate headquarters
was relocating from Houston, Texas to Tulsa, Oklahoma, which resulted in the accelerated vesting of
restricted stock awards in the period for Houston employees subject to a severance agreement. Of the
$4.4 million in share-based compensation for year ended December 31, 2015, approximately
$1.5 million was related to the accelerated vesting for employees impacted by the corporate relocation.
For the year ended December 31, 2014, approximately $2.9 million of the $8.6 million in share-based
compensation was related to the accelerated vesting.
F-40
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
12. Equity and Share-Based Compensation (Continued)
Unrecognized expense as of December 31, 2016 for all outstanding restricted stock units under the
2016 LTIP Plan was $11.4 million and will be recognized over a weighted average period of 1.7 years.
Stock Options
On December 31, 2016, the Company had 627,806 options outstanding pursuant to the 2016 LTIP.
Stock Option Awards granted under the 2016 LTIP vest ratably over a period of three years: one-sixth
will vest on the six-month anniversary of the Effective Date, an additional one-sixth will vest on the
twelve-month anniversary of the Effective Date, an additional one-third will vest on the twenty
four-month anniversary of the Effective Date and the final one-third will vest on the thirty six-month
anniversary of the Effective Date. Stock Option Awards expire 10 years from the grant date.
If an employee terminates employment prior to the vesting date, the outstanding award is
forfeited. Stock options are subject to accelerated vesting in the event a recipient’s employment is
terminated prior to the vesting date by the Company without ‘‘Cause’’ or by the participant with ‘‘Good
Reason’’ (each, as defined in the 2016 LTIP) or due to the participant’s death or disability.
The Company utilizes the Black-Scholes-Merton option pricing model to determine the fair value
of stock option awards. Determining the fair value of equity-based awards requires judgment, including
estimating the expected term that stock option awards will be outstanding prior to exercise and the
associated volatility.
The assumptions used to estimate the fair value of stock option awards are as follows:
Awards Issued in
Successor Period
Risk-free interest rate(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected option life(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected volatility(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Calculated fair value per stock option . . . . . . . . . . . . . . . . . . . . . . .
$
1.38%
—
5.96
60.0%
10.88
(1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate
assumption, matching the treasury yield terms to the expected life of the option.
(2) As the Company had no exercise history associated with stock options at the Effective
Date, expected option life assumptions were developed using the simplified method in
accordance with US GAAP. A change in the expected option life of +/(cid:3)2 years would
impact expense by $0.1 million and $(0.2) million for the Successor Period and
$0.9 million and $(1.1) million over the vesting period of three years.
(3) As the Company had no stock option history at the Effective Date, it utilized six peer
companies of comparable size and industry to estimate volatility utilizing a period that is
commensurate with the expected option life. The Company weighted historical volatility
and implied volatility 50/50 for those peer companies where both were available, with
volatility ranging in the peer companies from 38.5% to 65.9%.
F-41
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
12. Equity and Share-Based Compensation (Continued)
The following table summarizes the Company’s 2016 LTIP non-vested stock option activity for the
year ended December 31, 2016:
Options
Range of
Exercise Prices
Weighted
Average
Exercise Price
Weighted
Average
Remaining
Contractual
Term (Years)
Stock options outstanding at October 21, 2016
(Successor) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
628,468
2,035
—
(2,697)
19.66
20.97
$
$
— $
$
19.66
20.97
—
19.66
Stock options outstanding at December 31, 2016
(Successor) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
627,806
$
19.66
9.8
9.9
—
—
9.8
On December 31, 2016, the Company elected to early adopt ASU 2016-09 and chose to recognize
the effect of awards for which the requisite service is not rendered when the actual award is forfeited.
The share-based compensation costs (net of amounts capitalized to oil and gas properties) related
to stock options recognized as general and administrative expense by the Company for the Successor
Period was $0.8 million. For the Successor Period, the Company capitalized $0.2 million of qualifying
stock option share-based compensation costs to oil and gas properties.
Unrecognized expense as of December 31, 2016 for all outstanding stock options was $5.8 million
and will be recognized over a weighted average period of 1.8 years.
Non-Employee Director Restricted Stock Units Containing a Market Condition
On November 23, 2016 the Company issued certain restricted stock units to our non-employee
directors that contain a market vesting condition. These restricted stock units will vest (i) on the first
business day following the date on which the trailing 60-day average share price (including any
dividends paid) of the Company’s common stock is equal to or greater than $30.00 or (ii) upon a
change in control of the Company. Additionally, all unvested restricted stock units containing a market
vesting condition will be immediately forfeited upon the first to occur of (i) the fifth (5th) anniversary
of the grant date or (ii) any participant’s termination for any reason (except for a termination as part
of a change in control of the Company).
These restricted stock awards are accounted for as liability awards under FASB Accounting
Standards Codification (‘‘ASC’’) 718 as the awards allow for the withholding of taxes at the discretion
of the non-employee director. The liability is re-measured, with a corresponding adjustment to earnings,
at each fiscal quarter-end during the performance cycle. The liability and related compensation expense
of these awards for each period is recognized by dividing the fair value of the total liability by the
requisite service period and recording the pro rata share for the period for which service has already
been provided. As there are inherent uncertainties related to these factors and the Company’s
judgment in applying them to the fair value determinations, there is risk that the recorded
compensation may not accurately reflect the amount ultimately earned by the non-employee directors.
F-42
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
12. Equity and Share-Based Compensation (Continued)
A Monte Carlo simulation was prepared by a third party in order to determine the fair value of
these awards as of December 31, 2016. The assumptions used to estimate the fair value of restricted
stock unit awards with a market condition at December 31, 2016 are as follows:
Awards Issued in
Successor Period
Risk-free interest rate(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected volatility(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Market Price Hurdle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . .
Calculated fair value per restricted stock unit
$
$
1.89%
—
60.0%
30.00
17.71
(1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate
assumption, matching the treasury yield terms to the expected life of the restricted stock
unit.
(2) As the Company had no relevant history at the Effective Date, it utilized six peer
companies of comparable size and industry to estimate volatility utilizing a period that is
commensurate with the expected option life. The Company weighted historical volatility
and implied volatility 50/50 for those peer companies where both were available, with
volatility ranging in the peer companies from 39.8% to 61.4%.
The restricted stock unit awards issued to non-employee directors containing a market condition
has a derived service period of one year. At December 31, 2016 the Company recorded a $0.1 million
liability included within accrued liabilities on the consolidated balance sheet related to the market
condition awards. As of December 31, 2016, unrecognized stock-based compensation related to market
condition awards was $1.2 million and will be recognized over a weighted-average period of 0.9 years.
The following table reflects the outstanding restricted stock unit awards containing a market
conditions for the Successor Period:
Outstanding at October 21, 2016 (Successor) . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
76,296
— $
$
— $
— $
Outstanding at December 31, 2016 (Successor) . . . . . . . . .
76,296
$
—
17.71
—
—
17.71
Shares
Weighted Average
Fair Value
Unrestricted Common Share Awards
On November 7, 2016, 12,400 shares of unrestricted stock were issued to employees and
non-employee directors, which vested immediately upon issuance. For the Successor Period, total
expense associated with these unrestricted vested common shares was $0.2 million. There was no
unrecognized expense associated with these awards at December 31, 2016.
F-43
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
12. Equity and Share-Based Compensation (Continued)
Stock-Based Compensation Expense Summary
The following summarizes stock-based compensation expense for the periods presented (in
thousands):
Restricted stock units (Predecessor) . . . . . . . . . . .
Restricted stock units (Successor) . . . . . . . . . . . .
Stock options (Successor) . . . . . . . . . . . . . . . . . .
Restricted stock units with a market condition
(Successor) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrestricted stock awards (Successor) . . . . . . . . .
Total stock-based compensation . . . . . . . . . . . . .
Less: amounts capitalized to oil and natural gas
properties . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Successor
Predecessor
For the Period
October 21, 2016
through
For the Period
January 1, 2016
through
For the Years Ended
December 31,
December 31, 2016 October 20, 2016
2015
2014
$
— $
2,114
1,046
142
244
3,546
3,040
—
—
$ 5,755
—
—
$10,863
—
—
—
—
—
—
—
—
3,040
5,755
10,863
(637)
(476)
(1,347)
(2,244)
Net stock-based compensation . . . . . . . . . . . . . . .
$
2,909
$
2,564
$ 4,408
$ 8,619
13. Income Taxes
Under the Plan, a substantial portion of the Company’s pre-petition debt securities were
extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (‘‘CODI’’)
upon discharge of its outstanding indebtedness for an amount of consideration that is less than its
adjusted issue price. The Internal Revenue Code of 1986, as amended (‘‘IRC’’), provides that a debtor
in a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax
attributes by the amount of any CODI realized as a result of the consummation of a plan of
reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any
indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new
indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued.
As a result of the market value of equity upon emergence from Chapter 11 bankruptcy proceedings,
the estimated amount of U.S. CODI is approximately $1.2 billion, which will reduce the value of the
Company’s U.S. net operating losses and other assets. The actual reduction in tax attributes does not
occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1,
2017.
The Company anticipates a full reduction of its federal and state NOL carryforwards and a
reduction of the tax basis in its fixed assets effective January 1, 2017, pursuant to IRC section 108. The
anticipated result of this reduction is reflected in the deferred tax table below.
As of December 31, 2016, the Company has recorded a full valuation allowance against its net
deferred tax assets of $160.8 million, of which $157.1 million relates to deferred tax assets on the
Company’s property and equipment. The Company’s valuation allowance decreased by $532.6 million
from December 31, 2015 to December 31, 2016, which was primarily a result of the reduction in the
Company’s tax attributes pursuant to IRC Section 108.
F-44
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
13. Income Taxes (Continued)
As of December 31, 2016, the Company has not recorded a reserve for any uncertain tax positions.
The Company believes that there are no new items, nor changes in facts or judgments that should
impact the Company’s tax position. No federal income tax payments are expected in the upcoming four
quarterly reporting periods.
Successor
For the Period
October 21,
2016
through
December 31,
2016
(in thousands)
Predecessor
For the Period
January 1,
2016
through
October 20,
2016
For the Years Ended
December 31,
2015
2014
Current
United States . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
—
Total current . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred
United States . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
—
(in thousands)
— $ — $ —
809
—
—
—
—
809
— (3,864)
— (5,777)
— (9,641)
3,863
1,723
5,586
Total income tax provision (benefit) . . . . . . . . . . . . . .
$
— $
— $(9,641)
$6,395
The Company’s estimated income tax expense differs from the amount derived by applying the
statutory federal rate to pretax income principally due the effect of the following items:
Successor
For the Period
October 21,
2016
through
December 31,
2016
(in thousands)
9,930
$
Predecessor
For the Period
January 1,
2016
through
October 20,
2016
Years Ended
December, 31
2015
2014
(in thousands)
$ 1,323,079
$(1,806,836)
$123,324
35%
35%
35%
35%
Income (loss) before taxes . . . . . . . . . . . . . .
Statutory rate . . . . . . . . . . . . . . . . . . . . . . .
Income tax provision (benefit) computed at
statutory rate . . . . . . . . . . . . . . . . . . . . . .
3,475
463,078
(632,393)
43,164
Reconciling items:
State income taxes, net of federal benefit .
Change in valuation allowance . . . . . . . . .
Change in state rate . . . . . . . . . . . . . . . . .
Bankruptcy items . . . . . . . . . . . . . . . . . . .
Deferred tax true-ups . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . .
296
(3,876)
(1)
—
74
32
39,424
(528,706)
(153)
12,262
9,891
4,204
(65,904)
689,419
(612)
—
—
(151)
4,398
(42,134)
(414)
—
—
1,381
Total income tax provision (benefit) . . . . .
$
—
$
— $
(9,641)
$
6,395
F-45
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
13. Income Taxes (Continued)
Deferred income taxes primarily represent the net tax effect of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for
income tax purposes. The components of our deferred taxes are detailed in the table below (in
thousands):
Deferred tax assets—current
Derivative instruments and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax assets, current
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax assets—noncurrent
Successor
Predecessor
As of
December 31,
2016
As of
December 31,
2015
$
$
— $
—
— $
—
—
—
Federal tax loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State tax loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employee benefit plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and gas properties and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt restructuring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
3,649
157,113
—
27
(160,789)
146,641
13,848
1,160
465,028
66,693
—
(693,370)
Total deferred tax assets, noncurrent . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
Deferred tax liabilities—current
Derivative instruments and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
Total deferred tax liabilities—current . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
Deferred tax liabilities—noncurrent
Oil and gas properties and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax liabilities, noncurrent . . . . . . . . . . . . . . . . . . . . . . .
Reflected in the accompanying balance sheet as:
Net deferred tax asset, current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net deferred tax liability, current
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net deferred tax asset, noncurrent
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Net deferred tax liability, noncurrent . . . . . . . . . . . . . . . . . . . . . . . . . .
—
— $
— $
— $
— $
— $
$
$
$
$
$
—
—
—
—
—
—
—
—
—
F-46
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
14. Earnings (Loss) Per Share
Successor
The following table provides a reconciliation of net income attributable to common shareholders
and weighted average common shares outstanding for basic and diluted earnings per share for the
Successor Period:
For the Period
October 21, 2016 through
December 31, 2016
(in thousands, except
per share amounts)
Net Earnings:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Participating securities—non-vested restricted stock . . . . . .
Basic and diluted earnings . . . . . . . . . . . . . . . . . . . . . . . .
Common Shares:
Common shares outstanding—basic(1) . . . . . . . . . . . . . . .
Dilutive effect of potential common shares . . . . . . . . . . . . .
Common shares outstanding—diluted . . . . . . . . . . . . . . . .
Net Earnings Per Share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Antidilutive stock options(2) . . . . . . . . . . . . . . . . . . . . . . . . .
Antidilutive warrants(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
9,930
(280)
9,650
25,009,300
—
25,009,300
0.39
0.39
627
6,626
(1) Weighted-average common shares outstanding for basic and diluted earnings per share
purposes includes 17,533 shares of common stock that, while not issued and outstanding
at December 31, 2016, are required by the Plan to be issued.
(2) Amount represents options to purchase common stock that are excluded from the diluted
net earnings per share calculations because the options are antidilutive.
(3) Amount represents warrants to purchase common stock that are excluded from the
diluted net earnings per share calculations because the warrants are antidilutive.
F-47
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
14. Earnings (Loss) Per Share (Continued)
Predecessor
The following table provides a reconciliation of net income (loss) to preferred shareholders,
common shareholders, and participating securities for purposes of computing net income (loss) per
share for the Predecessor Period and the years ended December 31, 2015 and 2014:
For the Period
January 1,
2016 through
October 20,
2016
Years Ended December 31,
2015
2014
(in thousands, except per share amounts)
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Preferred Dividend(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,323,079
—
$(1,797,195) $116,929
(10,378)
(948)
Net income (loss) attributable to shareholders . . . . . . . . . . . . .
Participating securities—Series A Preferred Stock(2) . . . . . . . . .
Participating securities—Non-vested restricted stock(2) . . . . . . .
$ 1,323,079
—
(16,522)
$(1,798,143) $106,551
— (35,696)
(3,584)
—
Net income (loss) attributable to common shareholders . . . . . .
Weighted average shares outstanding . . . . . . . . . . . . . . . . . . . .
$ 1,306,557
10,645
$(1,798,143) $ 67,271
6,644
7,726
Basic and diluted net income (loss) per share . . . . . . . . . . . . .
$
122.74
$
(232.74) $
10.13
(1) Calculation of the preferred stock dividend is discussed in ‘‘—Note 11. Preferred Stock’’.
(2) As these shares are participating securities that participate in earnings, but are not required to
participate in losses, this calculation demonstrates that there is not an allocation of the loss to the
non-vested restricted stockholders.
15. Concentrations of Credit Risk
Financial instruments which potentially subject the Company to credit risk consist primarily of cash
balances, accounts receivable and, historically, derivative financial instruments.
The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may
exceed the federally insured limits. The Company has not experienced any significant losses from such
investments.
The Company normally sells production to a relatively small number of purchasers, as is customary
in the exploration, development and production business. The Company typically sells a substantial
portion of production under short-term (usually one-month) contracts tied to a local index. The
Company does not have any long-term, fixed-price sales contracts. For the Successor Period, two
purchasers accounted for 40% and 29%, respectively, of the Company’s revenue. For the Predecessor
Period, two purchasers accounted for 46% and 29%, respectively, of the Company’s revenue. For the
year ended December 31, 2015, two purchasers accounted for 43% and 25%, respectively, of the
Company’s revenue. For the year ended December 31, 2014, four purchasers accounted for 28%, 18%,
15% and 12% respectively, of the Company’s revenue.
Substantially all of the Company’s accounts receivable result from the sale of oil, natural gas and
natural gas liquids. At December 31, 2016, two purchasers accounted for approximately 44% and 26%,
F-48
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
15. Concentrations of Credit Risk (Continued)
respectively, of the accounts receivable balance. At December 31, 2015, three purchasers accounted for
approximately 33%, 29%, and 14%, respectively, of the accounts receivable balance.
Derivative financial instruments are generally executed with major financial institutions that expose
the Company to market and credit risks and which may, at times, be concentrated with certain
counterparties. The credit worthiness of the counterparties is subject to continual review. The Company
also has netting arrangements in place with counterparties to reduce credit exposure. The Company has
not experienced any losses from such instruments and had no derivative instruments in place at
December 31, 2016 or 2015.
16. Commitments and Contingencies
Contractual Obligations
At December 31, 2016, contractual obligations for drilling contracts, long-term operating leases and
other contracts are as follows (in thousands):
Total
2017
2018
2019
2020
2021 and
beyond
Drilling contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cancellable office lease commitments . . . . . . . . . .
$ — $ — $ — $ — $ — $ —
3,992
6,631
677
666
642
654
Net minimum commitments . . . . . . . . . . . . . . . . . . . .
$6,631
$642
$654
$666
$677
$ 3,992
For the Successor Period, the Predecessor Period and years ended December 31, 2015 and 2014,
the Company expensed $0.1 million, $4.3 million, $2.3 million and $2.3 million, respectively, for office
rent.
In addition to the commitments noted in the above table, the Company is party to a gas purchase,
gathering and processing contract in the Mississippian Lime region, which includes certain minimum
NGL volume commitments. To the extent we do not deliver natural gas volumes in sufficient quantities
to generate, when processed, the minimum levels of recovered NGLs, we would be required to
reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a
fee. We are currently delivering at least the minimum volumes required under these contractual
provisions. However, decreased drilling activity could result in the inability to meet these commitments
in the future.
Commitments related to ARO’s are not included in the table above. For additional information,
please see ‘‘—Note 9. Asset Retirement Obligations’’ for further discussion.
Litigation
The Company is involved in various matters incidental to its operations and business that might
give rise to a loss contingency. These matters may include legal and regulatory proceedings, commercial
disputes, claims from royalty, working interest and surface owners, property damage and personal injury
claims and environmental authorities or other matters. In addition, the Company may be subject to
customary audits by governmental authorities regarding the payment and reporting of various taxes,
governmental royalties and fees as well as compliance with unclaimed property (escheatment)
requirements and other laws. Further, other parties with an interest in wells operated by the Company
F-49
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
16. Commitments and Contingencies (Continued)
have the ability under various contractual agreements to perform audits of its joint interest billing
practices.
The Company vigorously defends itself in these matters. If the Company determines that an
unfavorable outcome or loss of a particular matter is probable and the amount of loss can be
reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes
available or as a result of legal or administrative rulings in similar matters or a change in applicable
law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated
loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a
material effect on its results of operations. As of December 31, 2016 and 2015, the Company’s total
accrual for all loss contingencies was $1.1 million.
F-50
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
17. Supplemental Information to Consolidated Statement of Cash Flows
The following table summarizes interest and income taxes paid for the periods presented and
supplemental non-cash investing and financing activities (in thousands):
Successor
Period
October 21,
2016 through
December 31,
2016
Period
January 1,
2016 through
October 20,
2016
Predecessor
Years Ended
December 31,
2015
2014
SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment . . .
Non-cash components of Pine Prairie Disposition:
—Asset retirement obligation disposed . . . . . . . .
—Accrual for miscellaneous liabilities assumed . .
—Other noncurrent assets sold . . . . . . . . . . . . . .
Non-cash component of Dequincy Divestiture:
—Asset retirement obligation disposed . . . . . . . .
Non-cash exchange of third lien notes for 2020
senior notes and 2021 senior notes . . . . . . . . . . .
Non-cash exchange of common equity of the
reorganized Company for second lien notes . . . . .
Non-cash exchange of common equity and warrants
of the reorganized Company for third lien notes .
Non-cash exchange of common equity and warrants
of the reorganized Company for 2020 senior
notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash exchange of common equity and warrants
of the reorganized Company for 2021 senior
notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash paid for interest, net of capitalized interest for
the Successor Period and the years ended
December 31, 2015 and 2014 of $0.7 million,
$4.9 million and $12.4 million, respectively (no
capitalized interest for the Predecessor Period) . .
Cash paid for reorganization items . . . . . . . . . . . . .
Cash paid for taxes . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
$
$
$
$
$
$
18. Related Party Transactions
8,135
$
12,995
$ 21,507
$ 95,000
— $
— $
— $
— $
— $
— $
— $ (7,652)
— $ (2,185)
371
— $
— $
— $ (4,699) $
— $
— $524,121
$
— $ 591,042
— $ 556,136
$
$
— $
— $
—
—
—
—
— $ 312,039
$
— $
—
— $ 361,050
$
— $
—
$
426
— $
— $
6,709
36,325
$161,285
$
— $
— $
— $
$129,511
—
209
During the Predecessor Period, First Reserve Corporation, which owned an economic interest in
the Company through FR Midstates Interholding LP, also owned an economic interest in Dixie Electric.
For the Predecessor Period, the Company paid approximately $1.7 million for electrical equipment and
related services from Dixie Electric. No transactions with Dixie Electric occurred in the Successor
Period or the years ended December 31, 2015 and 2014.
F-51
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
Note 19. Supplemental Oil and Gas Disclosures (Unaudited)
The supplemental data presented herein reflects information for all of the Company’s oil and
natural gas producing activities.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
The following table sets forth costs incurred related to the Company’s oil and natural gas activities
for the Successor Period, Predecessor Period and years ended December 31, 2015 and 2014 (in
thousands):
Successor
For the Period
October 21,
2016 through
December 31,
2016
For the Period
January 1,
2016 through
October 20,
2016
Predecessor
For the Year
Ended December 31,
2015
2014
Acquisition costs:
Proved properties . . . . . . . . . . . . . . . . . . . . . . . .
Unproved properties . . . . . . . . . . . . . . . . . . . . . .
Exploration costs . . . . . . . . . . . . . . . . . . . . . . . . . .
Development costs . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
— $
— $
1,430
—
17,708
6,869
—
121,668
8,448
—
274,978
—
25,576
672
525,941
Total costs incurred . . . . . . . . . . . . . . . . . . . .
$
19,138
$
128,537
$283,426
$552,189
Capitalized Costs
The following table sets forth the capitalized costs related to the Company’s oil and natural gas
producing activities as of December 31, 2016 and 2015 (in thousands):
Successor
Predecessor
December 31, 2016
December 31, 2015
Proved properties . . . . . . . . . . . . . . . . . . . . . . . .
Unproved properties not being amortized . . . . . .
$
Gross capitalized costs . . . . . . . . . . . . . . . . . . . .
Less: Accumulated depreciation, depletion,
$
573,150
65,080
638,230
3,666,403
—
3,666,403
amortization and impairment . . . . . . . . . . . . . .
(12,587)
(3,148,240)
Net capitalized costs . . . . . . . . . . . . . . . . . . . . .
$
625,643
$
518,163
At December 31, 2016, the Company had $65.1 million of oil and gas property costs that are not
being amortized, inclusive of $0.7 million of capitalized interest. The value of the Company’s oil and
gas properties not being amortized were determined as part of its application of fresh start accounting
and are entirely associated with the Company’s Mississippian Lime area. We expect the majority of
these costs associated with the Company’s Mississippian Lime area will be evaluated and either
impaired or become subject to depletion within ten years.
F-52
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
Note 19. Supplemental Oil and Gas Disclosures (Unaudited) (Continued)
Estimated Quantities of Proved Oil and Natural Gas Reserves
The reserve estimates at December 31, 2016 and 2015 for the Mississippian Lime and Anadarko
Basin areas and at December 31, 2014 for the Anadarko Basin area were based on reports prepared by
Cawley, Gillespie & Associates, Inc., independent reserve engineers. The reserve estimates at
December 31, 2014 for the Gulf Coast area and for the Mississippian Lime area were based on a
report prepared by Netherland, Sewell and Associates, Inc., independent reserve engineers.
The Company emphasizes that reserve estimates are inherently imprecise and that estimates of
new discoveries and undeveloped locations are more imprecise than estimates of established proved
producing oil and gas properties. Accordingly, these estimates are expected to change as future
information becomes available. Proved oil and natural gas reserves are the estimated quantities of oil
and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices
and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are
proved reserves that can be expected to be recovered through existing wells and equipment in place
and under operating methods being utilized at the time the estimates were made.
The following table sets forth the Company’s net proved, proved developed and proved
undeveloped reserves at December 31, 2016, 2015 and 2014:
Oil
(MBbl)
NGL
(MBbl)
Gas
(MMcf)
Total
(MBoe)
2014 (Predecessor)
Proved Reserves
Beginning Balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revision of previous estimates . . . . . . . . . . . . . . . . . . . . . .
Extensions, discoveries and other additions . . . . . . . . . . . . .
Sales of reserves in place . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of reserves in place . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
54,899
(11,563)
30,232
(10,182)
—
(5,144)
26,156
(4,444)
15,414
(2,181)
—
(2,417)
280,198
(41,510)
188,336
(24,166)
—
(25,013)
127,755
(22,925)
77,035
(16,391)
—
(11,730)
Net proved reserves at December 31, 2014 . . . . . . . . . . . . . . .
58,242
32,528
377,845
153,744
Proved developed reserves, December 31, 2014 . . . . . . . . . . . .
27,181
16,443
179,972
73,620
Proved undeveloped reserves, December 31, 2014 . . . . . . . . . .
31,061
16,085
197,873
80,124
2015 (Predecessor)
Proved Reserves
Beginning Balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revision of previous estimates . . . . . . . . . . . . . . . . . . . . . .
Extensions, discoveries and other additions . . . . . . . . . . . . .
Sales of reserves in place . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of reserves in place . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
58,242
(30,490)
2,189
(2,871)
2,437
(4,794)
32,528
(15,495)
1,371
(843)
1,157
(2,473)
377,845
(178,287)
17,026
(7,834)
15,145
(28,403)
153,744
(75,700)
6,398
(5,019)
6,118
(12,001)
Net proved reserves at December 31, 2015 . . . . . . . . . . . . . . .
24,713
16,245
195,492
73,540
Proved developed reserves, December 31, 2015 . . . . . . . . . . . .
23,006
15,376
184,365
69,110
Proved undeveloped reserves, December 31, 2015 . . . . . . . . . .
1,707
869
11,127
4,430
F-53
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
Note 19. Supplemental Oil and Gas Disclosures (Unaudited) (Continued)
Oil
(MBbl)
NGL
(MBbl)
Gas
(MMcf)
Total
(MBoe)
2016 (Predecessor)
Proved Reserves
Beginning Balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revision of previous estimates . . . . . . . . . . . . . . . . . . . . . .
Extensions, discoveries and other additions . . . . . . . . . . . . .
Sales of reserves in place . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of reserves in place . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24,713
(3,089)
1,566
—
—
(2,964)
16,245
(459)
840
—
—
(1,932)
195,492
(946)
11,052
—
—
(23,215)
73,540
(3,706)
4,249
—
—
(8,765)
Net proved reserves at October 20, 2016 . . . . . . . . . . . . . . . .
20,226
14,694
182,383
65,318
Proved developed reserves, October 20, 2016 . . . . . . . . . . . . .
20,226
14,694
182,383
65,318
Proved undeveloped reserves, October 20, 2016 . . . . . . . . . . .
—
—
—
—
2016 (Successor)
Proved Reserves
Beginning Balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revision of previous estimates . . . . . . . . . . . . . . . . . . . . . .
Extensions, discoveries and other additions . . . . . . . . . . . . .
Sales of reserves in place . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of reserves in place . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20,226
19,137
22,571
—
—
(544)
14,694
11,421
11,186
—
—
(429)
182,383
147,688
147,236
—
—
(4,948)
65,318
55,172
58,296
—
—
(1,798)
Net proved reserves at December 31, 2016 . . . . . . . . . . . . . . .
61,390
36,872
472,359
176,988
Proved developed reserves, December 31, 2016 . . . . . . . . . . . .
19,698
16,349
201,454
69,622
Proved undeveloped reserves, December 31, 2016 . . . . . . . . . .
41,692
20,523
270,905
107,366
Revision of Previous Estimates
For the Successor Period, the Company had positive revisions of 55,172 MBoe associated with its
proved undeveloped reserves. Upon the Company’s emergence on the Effective Date, it undertook a
process to review its five-year development schedule in light of improved commodity pricing and the
significant improvement in the Company’s liquidity and outstanding long-term debt. In developing the
Company’s updated five-year development schedule, the Company considered the forward pricing
curve, the returns expected of its drilling program and cash available during this time period, which
would include cash on hand, cash generated by operations and cash from borrowings. Based upon these
factors, the Company developed an updated five-year development plan and booked proved
undeveloped reserves based upon this expected development plan. Proved undeveloped reserves that
were removed from proved category in prior years but subsequently reinstated after this review were
classified as a revision in the above tables.
For the year ended December 31, 2015, the Company had net negative revisions of 75,700 MBoe
related to proved undeveloped reserves, of which approximately 98% related to reductions in the
Mississippian Lime area due to the transfer of 77,362 MBoe of proved undeveloped reserves
comprising $179.0 million of PV-10 value (at SEC pricing) to the probable reserves category due to
F-54
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
Note 19. Supplemental Oil and Gas Disclosures (Unaudited) (Continued)
uncertainty around financing the development of our proved undeveloped reserves within a five year
period.
For the year ended December 31, 2014, the Company had net negative revisions of 22,925 MBoe
related to proved undeveloped reserves, of which 3,084 MBoe related to reductions in our Gulf Coast
area, and 22,138 MBoe related to reductions in our Anadarko Basin area, partially offset by 2,297
MBoe in positive revisions in the Mississippian Lime area. These net negative revisions in the Gulf
Coast were primarily due to our lack of future development plans in this area. The net negative
revisions in the Anadarko Basin were primarily due to our current drilling plans, which did not allow
for development of these proved undeveloped reserves within five years of their initial booking.
Extensions, Discoveries and Other Additions
For the Successor Period, the Company had 58,296 MBoe of extensions and discoveries associated
with its proved undeveloped reserves in the Mississippian Lime area. Upon the Company’s emergence
on the Effective Date, it undertook a process to review its five-year development schedule in light of
improved commodity pricing and the significant improvement in the Company’s liquidity and
outstanding long-term debt. In developing the Company’s updated five-year development schedule, the
Company considered the forward pricing curve, the returns expected of its drilling program and cash
available during this time period, which would include cash on hand, cash generated by operations and
cash from borrowings. Based upon these factors, the Company developed an updated five-year
development plan and booked proved undeveloped reserves based upon this expected development
plan. Proved undeveloped reserves that were not included in any proved category in prior years but
included in the Company’s updated five-year development schedule were classified as an extension in
the above tables.
For the Predecessor Period and the years ended December 31, 2015 and 2014, the Company had
4,249 MBoe, 6,398 MBoe and 77,035 MBoe, respectively, of additions from extensions and discoveries,
all of which related to the Mississippian Lime area.
Sales of Reserves in Place
For the year ended December 31, 2015, the Company had 5,019 MBoe in sales of reserves in
place, of which 2,307 MBoe of the sale related to the Dequincy Divestiture, which closed on April 21,
2015, and 2,712 MBoe resulted from the swap of leasehold interests in the Mississippian Lime area in
the second quarter of 2015.
For the year ended December 31, 2014, the Company had 16,391 MBoe in sales of reserves in
place related to the Pine Prairie Disposition, which closed on May 1, 2014.
Purchases of Reserves in Place
For the year ended December 31, 2015, the Company had 6,118 MBoe of additions from
purchases of reserves in place resulting from a swap of leasehold interests in the Mississippian Lime
area.
F-55
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
Note 19. Supplemental Oil and Gas Disclosures (Unaudited) (Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The standardized measure represents the present value of estimated future cash inflows from
proved oil and natural gas reserves, less future development, production, plugging and abandonment
costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.
Production costs do not include depreciation, depletion and amortization of capitalized acquisition,
exploration and development costs.
Our estimated proved reserves and related future net revenues and standardized measure were
determined using the unweighted arithmetic average first-of-the-month price for the preceding
12-month period, without giving effect to derivative transactions, and were held constant throughout
the life of the properties. Estimated future production of proved reserves and estimated future
production and development costs of proved reserves are based on current costs and economic
conditions. The following table sets forth the benchmark prices used to determine our estimated proved
reserves for the periods indicated:
Successor
Predecessor
At December 31,
2016
At December 31,
2015
2014
Oil and Natural Gas Prices:
Oil (per barrel) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
NGL (per barrel) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Natural gas (per million British thermal units) . . . . . . . . . . . . . . . . . $
42.75
15.29
2.48
$50.28
$17.44
$ 2.59
$94.99
$39.17
$ 4.35
The following table sets forth the standardized measure of discounted future net cash flows from
projected production of the Company’s oil and natural gas reserves at December 31, 2016, 2015, and
2014 (in thousands):
Successor
Predecessor
At December 31,
2016
Year Ended December 31,
2015
2014
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Future production costs . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future development costs . . . . . . . . . . . . . . . . . . . . . . . . . .
Future income tax expense . . . . . . . . . . . . . . . . . . . . . . . . .
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% annual discount for estimated timing of cash flows . . . .
4,186,389
(2,078,640)
(692,533)
(106,563)
1,308,653
(778,703)
$ 1,902,184
(1,024,314)
(47,532)
$ 8,405,916
(2,669,000)
(751,353)
— (1,113,908)
830,338
(317,519)
3,871,655
(1,998,294)
Standardized measure of discounted future net cash flows . . $
529,950
$
512,819
$ 1,873,361
F-56
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
Note 19. Supplemental Oil and Gas Disclosures (Unaudited) (Continued)
The following table sets forth the changes in the standardized measure of discounted future net
cash flows applicable to proved oil and natural gas reserves for the Successor Period, Predecessor
Period and the years ended December 31, 2015 and 2014 (in thousands):
Successor
For the Period
October 21, 2016
through
December 31, 2016
For the Period
January 1, 2016
through
October 20, 2016
Standardized measure, beginning of period $
Net changes in prices and production costs
Net changes in future development costs . .
Sales of oil and natural gas, net . . . . . . . .
Extensions . . . . . . . . . . . . . . . . . . . . . . . .
Discoveries . . . . . . . . . . . . . . . . . . . . . . .
Purchases of reserves in place . . . . . . . . .
Divestiture of reserves . . . . . . . . . . . . . . .
Revisions of previous quantity estimates . .
Previously estimated development costs
incurred . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount . . . . . . . . . . . . . . . .
Net change in income taxes . . . . . . . . . . .
Changes in timing, other . . . . . . . . . . . . .
$
349,905
78,103
2,022
(27,292)
102,087
—
—
—
102,623
—
5,832
(48,206)
(35,124)
512,819
(113,313)
175
(116,043)
29,871
—
—
—
(22,194)
29,975
42,735
—
(14,120)
Predecessor
Year Ended December 31,
2015
2014
$ 1,873,361
(960,245)
57,357
(232,630)
38,550
—
34,369
(77,445)
(1,174,997)
$1,790,446
(190,256)
66,828
(536,362)
1,094,606
—
—
(390,264)
(205,233)
198,564
238,639
513,024
4,272
160,663
206,783
(230,401)
106,551
Standardized measure, end of period . . . . $
529,950
$
349,905
$
512,819
$1,873,361
F-57
MIDSTATES PETROLEUM COMPANY, INC.
Notes to Consolidated Financial Statements (Continued)
Note 20. Selected Quarterly Financial Data (Unaudited)
The following table presents selected quarterly financial data derived from the Company’s
unaudited interim financial statements. The following data is only a summary and should be read with
the Company’s historical consolidated financial statements and related notes contained in this
document.
2016 (Successor)
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income available to common shareholders . . . .
Net income per share:
$
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter(1)
(in thousands, except per share amounts)
— $
—
—
—
— $
—
—
—
— $
—
—
—
48,525
10,673
9,930
9,650
Basic and Diluted . . . . . . . . . . . . . . . . . . . . . . .
$
— $
— $
— $
0.39
Shares used in computation:
Basic and Diluted . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
25,009
2016 (Predecessor)
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss available to common shareholders . . . . . . .
Net loss per share:
$ 51,961
(135,119)
(179,274)
(179,274)
$ 62,559
(52,759)
8,962
8,864
$ 64,193
(12,944)
(38,384)
(38,384)
$
14,514
(4,101)
1,531,775
1,515,351
Basic and Diluted . . . . . . . . . . . . . . . . . . . . . . .
$
(16.88) $
0.83
$
(3.60) $
142.19
Shares used in computation:
Basic and Diluted . . . . . . . . . . . . . . . . . . . . . . .
10,621
10,653
10,657
10,657
2015 (Predecessor)
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss available to common shareholders . . . . . . .
Net loss per share:
$ 111,198
(166,101)
(193,554)
(193,685)
$ 74,754
(553,584)
(598,437)
(599,106)
$ 110,363
(453,790)
(494,342)
(494,490)
$
68,830
(470,328)
(510,862)
(510,862)
Basic and Diluted . . . . . . . . . . . . . . . . . . . . . . .
$
(28.80) $
(88.44) $
(72.34) $
(48.48)
Shares used in computation:
Basic and Diluted . . . . . . . . . . . . . . . . . . . . . . .
6,726
6,774
6,835
10,537
(1) Fourth quarter for the 2016 Predecessor Period is for the period October 1, 2016 through
October 20, 2016. Fourth quarter for the 2016 Successor Period is the period October 21, 2016
through December 31, 2016.
F-58
MIDSTATES PETROLEUM COMPANY, INC.
RATIO OF EARNINGS TO FIXED CHARGES AND TO COMBINED FIXED CHARGES AND
PREFERRED DIVIDENDS
EXHIBIT 12.1
(In thousands, except ratios)
Successor
Predecessor
For the Period
October 21, 2016
through
For the Period
January 1, 2016
through
Year Ended December 31,
December 31, 2016 October 20, 2016
2015
2014
2013
2012
$
9,930 $
1,323,079
$(1,806,836)
$123,324
$(490,514)
$ 7,789
1,409
61,773
151,832
129,691
77,179
11,711
15
63
41
—
4,587
699
23,960
11,316
699
4,961
7,857
698
10,683
5,960
1,050
1,529
497
340
Earnings available before fixed
. . . . . . .
charges:
Pre-tax income (loss)
Interest expense (Predecessor
Period excludes interest
expense of $89.5 million on
senior and secured notes) . . .
Amortization of capitalized
interest . . . . . . . . . . . . . . .
Loan cost amortization . . . . . .
Portion of rental expense which
. . .
represents interest factor
Total earnings available for
fixed charges . . . . . . . . . .
$
11,458 $
1,390,138
$(1,619,029)
$266,531
$(396,195)
$22,419
Interest expense (Predecessor
Period excludes interest expense
of $89.5 million on senior and
secured notes) . . . . . . . . . . . .
Capitalized interest . . . . . . . . . .
Loan cost amortization . . . . . . . .
Portion of rental expense which
represents interest factor . . . . .
Total fixed charges . . . . . . . . .
Ratio of earnings to fixed charges
Insufficient coverage . . . . . . . . .
. . . . . . . . . .
Total fixed charges
Pre-tax preferred dividends(1) . . .
Total fixed charges plus
$
$
$
$
1,409 $
728
63
41
61,773
—
4,587
699
$
151,832
4,859
11,316
$129,691
12,415
7,857
$ 77,179
32,245
5,960
$11,711
11,175
1,529
699
698
497
340
2,241 $
67,059
$
168,706
$150,661
$ 115,881
$24,755
5.1x
— $
2,241 $
—
20.7x
—
1.8x
—
—
— $ 1,787,735
$
— $ 512,076
$ 2,336
67,059
—
$
168,706
23,545
$150,661
30,863
$ 115,881
38,588
$24,755
10,844
preferred dividends . . . . .
$
2,241 $
67,059
$
192,251
$181,524
$ 154,469
$35,599
Ratio of earnings to combined
fixed charges and preferred
dividends . . . . . . . . . . . . . . .
Insufficient coverage . . . . . . . . .
$
5.1x
— $
20.7x
—
1.5x
—
—
— $ 1,811,280
$
— $ 550,664
$13,180
(1) Prior to October 1, 2012, the Company did not have any preferred stock outstanding. Preferred dividends shown
herein relate to the Company’s Series A Mandatorily Convertible Preferred Stock (‘‘Series A Preferred Stock’’)
issued on October 1, 2012, which allows, at the Company’s option, for the 8% annual dividend payment to be made
either in cash or through an adjustment to the Series A Preferred Stock liquidation preference. Pre-tax preferred
stock dividend amounts for the years ended December 31, 2015, 2014, 2013 and 2012 were calculated utilizing the
Company’s effective tax rate for the applicable periods (0.5%, 5.2%, 29.9% and 40.1%, respectively) and represent
the notional dividend amount as though paid in cash, rather than through an adjustment to the Series A Preferred
Stock liquidation preference. On September 30, 2015, the Series A Preferred Stock converted into 3,738,424 shares
of common stock.
List of Subsidiaries of Midstates Petroleum Company, Inc.
Entity
EXHIBIT 21.1
State of Formation
Midstates Petroleum Company LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delaware
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have issued our report dated March 30, 2017, with respect to the consolidated financial
statements included in the Annual Report of Midstates Petroleum Company, Inc. on Form 10-K for the
year ended December 31, 2016. We consent to the incorporation by reference of said report in the
Registration Statements of Midstates Petroleum Company, Inc. on Form S-8 (File No. 333-214213) and
on Form S-1 (File No. 333-215602).
EXHIBIT 23.1
/s/ GRANT THORNTON LLP
Kansas City, Missouri
March 30, 2017
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Amendment No. 1 to Registration Statement
No. 333-215602 on Form S-1 and Registration Statement No. 333-214213 on Form S-8 of our report
dated March 30, 2016, relating to the consolidated financial statements of Midstates Petroleum
Company, Inc. and subsidiary (which report expresses an unqualified opinion and includes an
explanatory paragraph regarding going concern uncertainty), appearing in this Annual Report on
Form 10-K of Midstates Petroleum Company, Inc. and subsidiary for the year ended December 31,
2016.
EXHIBIT 23.2
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 30, 2017
EXHIBIT 23.3
24MAR201706485161
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the references to our firm, in the context in which they appear, and to the
references to and the incorporation by reference of our report as of December 31, 2014, included in
the Annual Report on Form 10-K of Midstates Petroleum Company, Inc. for the fiscal year ended
December 31, 2016, as well as in the notes to the financial statements included therein.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ C.H. (SCOTT) REES III
Name: C.H. Scott Rees III, P.E.
Title: Chairman and Chief Executive Officer
Dallas, Texas
March 30, 2017
EXHIBIT 23.4
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
Cawley, Gillespie & Associates, Inc., hereby consents to the references to our firm, in the context
in which they appear, and to the references to and the incorporation by reference of our summary
report dated January 24, 2017 included in the Annual Report on Form 10-K of Midstates Petroleum
Company, Inc. for the fiscal year ended December 31, 2016, as well as in the notes to the financial
statements included therein. We hereby further consent to the incorporation by reference of the
references to our firm, in the context in which they appear, and to our summary report dated
January 24, 2017, into Midstates Petroleum Company, Inc.’s previously filed Registration Statement
No. 333-214213 on Form S-8 and Registration Statement No. 333-215602 on Form S-1.
By: /s/ J. ZANE MEEKINS
Name:
Title:
J. Zane Meekins
Executive Vice President
Cawley, Gillespie & Associates, Inc.
Texas Registered Engineering Firm F-693
Fort Worth, Texas
March 30, 2017
EXHIBIT 31.1
I, Frederic F. Brace, certify that:
CERTIFICATION
1.
I have reviewed this Annual Report on Form 10-K for the period ending December 31, 2016 (the
‘‘report’’) of Midstates Petroleum Company, Inc. (the ‘‘registrant’’);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting
that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal
quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation
of internal control over financial reporting, to the registrant’s auditors and the audit committee of
the registrant’s board of directors (or persons performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely affect the registrant’s
ability to record, process, summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: March 30, 2017
/s/ FREDERIC F. BRACE
Frederic F. Brace
President and Chief Executive Officer
(Principal Executive Officer)
EXHIBIT 31.2
I, Nelson M. Haight, certify that:
CERTIFICATION
1.
I have reviewed this Annual Report on Form 10-K for the period ending December 31, 2016 (the
‘‘report’’) of Midstates Petroleum Company, Inc. (the ‘‘registrant’’);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and
procedures to be designed under our supervision, to ensure that material information relating
to the registrant, including its consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting
that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal
quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation
of internal control over financial reporting, to the registrant’s auditors and the audit committee of
the registrant’s board of directors (or persons performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely affect the registrant’s
ability to record, process, summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial reporting.
Date: March 30, 2017
/s/ NELSON M. HAIGHT
Nelson M. Haight
Executive President and Chief Financial Officer
(Principal Financial Officer)
CERTIFICATION
EXHIBIT 32.1
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, Frederic F. Brace, President and Chief Executive Officer of Midstates Petroleum
Company, Inc. (the ‘‘Company’’), certifies that, to his knowledge:
1.
2.
the Annual Report on Form 10-K of the Company for the period ending December 31, 2016,
as filed with the Securities and Exchange Commission on the date hereof (the ‘‘Report’’), fully
complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended; and
the information contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of the Company.
Date: March 30, 2017
/s/ FREDERIC F. BRACE
Frederic F. Brace
President and Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION
EXHIBIT 32.2
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, Nelson M. Haight, Executive Vice President and Chief Financial Officer of Midstates
Petroleum Company, Inc. (the ‘‘Company’’), certifies that, to his knowledge:
1.
2.
the Annual Report on Form 10-K of the Company for the period ending December 31, 2016,
as filed with the Securities and Exchange Commission on the date hereof (the ‘‘Report’’), fully
complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended; and
the information contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of the Company.
Date: March 30, 2017
/s/ NELSON M. HAIGHT
Nelson M. Haight
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Exhibit 99.1
29MAR201710163045
January 24, 2017
Mr. Jeromy Garcia
General Manager
MidCon/Anadarko Assets & Reserves
Midstates Petroleum Company, Inc.
321 S. Boston Ave., Suite 1000
Tulsa, OK 74103
Re: Evaluation Summary—SEC Pricing
Midstates Petroleum Company, Inc. Interests
Texas and Oklahoma
Proved Reserves
As of January 1, 2017
Dear Mr. Garcia:
As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting
economics attributable to the above captioned interests as of January 1, 2017 in certain properties located
in Texas and Oklahoma. It is our understanding that the proved reserves estimated in this report constitute
100% of all proved reserved owned by Midstates Petroleum Company, Inc. This report, completed on
January 24, 2017, has been prepared for use in filings with the SEC by Midstates Petroleum Company, Inc.
Composite reserve estimates and economic forecasts are summarized below:
Net Reserves
Oil/Condensate
Gas
NGL
Revenue
Oil/Condensate
Gas
NGL
Severance and Ad Valorem Taxes
Operating Expenses
Investments
Operating Income (BFIT)
Discounted @ 10%
Proved
Proved
Developed
Producing
Proved
Developed
Non-Producing
Proved
Undeveloped
- Mbbl
- MMcf
- Mbbl
61,389.8
472,359.4
36,871.9
18,158.2
181,118.9
14,751.8
- M$
- M$
- M$
- M$
- M$
- M$
- M$
- M$
2,527,951.8
1,094,533.9
563,903.4
239,658.7
1,838,982.4
692,533.3
1,415,214.9
578,154.3
742,487.1
418,564.8
223,475.5
89,294.2
718,222.2
16,338.7
560,672.3
341,108.6
1,539.8
20,335.1
1,596.9
63,593.9
47,197.8
24,576.3
9,680.6
75,723.6
8,520.6
41,443.2
20,552.7
41,691.8
270,905.3
20,523.2
1,721,870.9
628,771.2
315,851.8
140,683.9
1,045,036.4
667,674.1
813,099.3
216,493.1
The discounted value shown above should not be construed to represent an estimate of the fair
market value by Cawley, Gillespie & Associates, Inc.
Midstates Petroleum Company, Inc. Interests
As of January 24, 2017
Page 2 of 2
As requested, hydrocarbon pricing of $42.75 per barrel of oil/condensate (WTI Cushing) and $2.481
per MMBtu of gas (Henry Hub) was applied without escalation. In accordance with the Securities and
Exchange Commission guidelines, these prices were determined as an unweighted arithmetic average of
the first-day-of-the-month price for the previous 12 months. NGL prices were forecast as fraction of the
above oil prices. Basis differentials were applied to the oil and gas prices, and deductions were applied to
the net gas volumes for fuel and shrinkage. The adjusted volume-weighted average product prices over the
life of the properties are $41.18 per barrel of oil, $2.32 per Mcf of gas, and $15.29 per barrel of NGL.
Operating expenses were based on operating expense records of Midstates Petroleum Company, Inc.
Drilling and completion costs were based on estimates provided by Midstates Petroleum Company, Inc.
and reviewed by Cawley, Gillespie & Associates. Severance tax and ad valorem rates were specified by
state/county based on actual rates. Plugging and abandonment costs of $30,000 to $48,000 (net of salvage
value) were applied to all wells. Neither expenses nor investments were escalated.
The proved reserve classifications conform to criteria of the Securities and Exchange Commission.
The reserves were estimated using a combination of the production performance, volumetric and analogy
methods, in each case as we considered to be appropriate and necessary to establish the conclusions set
forth herein. The reserves and economics are predicated on the regulatory agency classifications, rules,
policies, laws, taxes and royalties in effect on the effective date except as noted herein. The possible effects
of changes in legislation or other Federal or State restrictive actions have not been considered. All reserve
estimates represent our best judgment based on data available at the time of preparation and assumptions
as to future economic and regulatory conditions. It should be realized that the reserves actually recovered,
the revenue derived therefrom and the actual cost incurred could be more or less than the estimated
amounts.
The reserve estimates were based on interpretations of factual data furnished by Midstates Petroleum
Company, Inc. Ownership interests were supplied by Midstates Petroleum Company, Inc. and were
accepted as furnished. To some extent, information from public records has been used to check and/or
supplement these data. The basic engineering and geological data were utilized subject to third party
reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe
that we are not justified in relying on such data. An on-site inspection of these properties has not been
made nor have the wells been tested by Cawley, Gillespie & Associates, Inc.
Our work-papers and related data are available for inspection and review by authorized parties.
Respectfully submitted,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
29MAR201710145497
EXECUTIVE OFFICERS
Frederic F. Brace
President & Chief Executive Officer
Nelson M. Haight
Executive Vice President
& Chief Financial Officer
Mitchell G. Elkins
Executive Vice President—Operations
Scott C. Weatherholt
Vice President—General Counsel
& Corporate Secretary
Vice President—Land
Amelia K. Harding
Vice President—Human Resources
& Administration
BOARD OF DIRECTORS
Alan J. Carr
Chairman and Director
Frederic F. Brace
Director
Patrice D. Douglas
Director
Neal P. Goldman
Director
Michael S. Reddin
Director
Todd R. Snyder
Director
Bruce H. Vincent
Director
Midstates Petroleum Company, Inc.
321 South Boston Avenue, Suite 1000
Tulsa, Oklahoma 74103
918.947.8550
www.midstatespetroleum.com