PetroQuest Energy Annual Report 2015

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FY2015 Annual Report · PetroQuest Energy

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www.PETROQUEST.COM

NYSE:PQ

2015
2015

Annual Report

Corporate Profile

Letter To Shareholders

CORPORATE INFORMATION

Founded in 1985, PetroQuest Energy is a U.S.-focused exploration and development
company of crude oil and natural gas in Louisiana, Oklahoma and Texas.
Commodity prices change but our strategy is strong and flexible enough to withstand a
down cycle and persevere. Our industry is a business of long-term resourcefulness
balanced with near-term inventiveness. Since our founding, we’ve focused on building an
energy company with the diversity to preserve returns through any cycle. We believe PetroQuest
will persevere through the current commodity environment, add incrementally to its reserve and
production base, improve well performance, and be well prepared for the future.

BOARD OF DIRECTORS

Charles T. Goodson
Chairman of the Board,
Chief Executive Officer, and President

W.J. Gordon III *#^
President, CEO, and Founder of TGA Global Consulting Group

Michael L. Finch *#^
Dear Fellow Shareholders:
Private Investments

CORPORATE ADDRESS

PetroQuest Energy, Inc.
400 East Kaliste Saloom Road, Suite 6000
Lafayette, Louisiana 70508
Telephone: (337) 232-7028
Fax: (337) 232-0044
Web: www.petroquest.com

Core Assets

Oklahoma Woodford
Reserves: 11%
Production: 27%

Reserves: 64%
Production: 33%

Reserves: 25%
Production: 40%

E. Wayne Nordberg *#^
Hollow Brook Associates, LLC

Charles F. Mitchell II, M.D. *#^
Physician, Private Investments
Everyone has made their best guess about how long this downturn
will last. Instead of guessing, we took proactive steps to prepare for a
lower for longer commodity price scenario. We sold non-core assets in
the Mid-Continent, paid off all of our bank debt and closed on a private
exchange offer that lowered our debt profile, extended maturities and
substantially reduced annual fixed charges. In response to the lower
commodity price environment, our 2016 capital expenditure guidance
is approximately 70% less than 2015 showing our commitment to cost
control and liquidity preservation.
^ Member of the Nominating and Corporate Governance Committee

William W. Rucks, IV *#^
Private Investments

* Member of the Compensation Committee
# Member of the Audit Committee

SENIOR MANAGEMENT

Charles T. Goodson
Chairman of the Board,
Chief Executive Officer, and President

If there is a bright spot in the current commodity environment, we
believe it’s the future for natural gas. Domestic supply and demand
fundamentals are rapidly changing for the better. On the supply side of
the equation, the natural gas rig count is now below 100 rigs working,
off of the 2015 high seen in January at 329 gas rigs. As a result, we
are seeing natural gas production begin to roll over. And natural gas
demand, notwithstanding the mild winter, is increasing as natural gas
is replacing coal as a cleaner and more cost effective alternative for
domestic power generation, and U.S. liquefied natural gas (LNG) is
now being exported overseas. The first lower 48 U.S. LNG export ship
left Cameron Parish, Louisiana on February 24 to deliver its shipment
to Brazil. This historic event marks a new paradigm for the country in
energy trade and allows U.S. producers to compete for global demand.

J. Bond Clement
Executive Vice President
Chief Financial Officer, and Treasurer

Art M. Mixon
Executive Vice President
Operations and Production

Tracy Price
Executive Vice President
Business Development & Land

Our 30 year history in the oil and gas business taught us how to
navigate turbulent markets. Success in a low price environment requires a
quality asset base, liquidity and a relentless commitment from a team to
Edward E. Abels, Jr.
recognize opportunities and preserve value. When prices recover, not only
Executive Vice President, General Counsel,
and Corporate Secretary
will we bridge to the other side of this downturn, but return to a growth
path consistent with our execution over our long corporate history

Stephen H. Green
Senior Vice President
Significant Transactions
Exploration

Mark K. Castell
Vice President - Oklahoma Assets

In June of 2015, we sold the majority of our interests in the Woodford
Shale and Mississippian Lime for gross proceeds of $280 million.
By moving quickly and efficiently, we were able to realize substantial
value for these assets that provided an infusion of cash we in turn used
to pay down debt. By focusing on two primary operating regions, instead

Edgar A. Anderson
Vice President - ArkLaTex

EXPLORATION OFFICES

Charles T. Goodson
Chairman, President & CEO

1800 Hughes Landing Blvd., Suite 200
The Woodlands, Texas 77380
Telephone: (281) 465-3900
Fax: (281) 465-3999

of three, we can concentrate our capital and efforts on our highest return
projects – our multi-year development of the Carthage Field in East
Texas, where we’ve assembled a premier asset in the core of the Cotton
Valley trend, and our low decline Gulf Coast projects at Thunder Bayou
and La Cantera.

1717 S. Boulder, Suite 201
Tulsa, Oklahoma 74119
Telephone: (918) 582-2770
Fax: (918) 582-2778

American Stock Transfer & Trust Company
59 Maiden Lane
New York, New York 10038
Telephone: (718) 921-8145

TRANSFER AGENT AND REGISTRAR
More recently in early 2016, we closed on a private exchange offer
of $214.4 million of our outstanding 10% Senior Notes due 2017 for
$53.6 million of cash, $144.6 million in aggregate principal of newly
issued 10% Second Lien Senior Secured Notes due 2021 and 4.2 million
shares of our common stock. The transaction extends the maturities of
a significant portion of our debt out to 2021, eliminates $70 million in
INDEPENDENT AUDITORS
debt, and reduces our annual interest payments by $7 million a year.
In total, since the end of 2014, we have extinguished approximately
$145 million in debt. We estimate that the resulting reduction in interest
expense will provide an approximate $0.33/Mcfe improvement on 2016
cash margins.

Ernst & Young LLP
New Orleans, Louisiana 70170

LEGAL COUNSEL

Quality Assets

Porter & Hedges, LLP
Houston, Texas 77002

ANNUAL MEETING

Onebane Law Firm
Lafayette, Louisiana 70508

The Company’s Annual Meeting of Stockholders
will be held at 9:00 A.M. CDT on May 18, 2016, at the
City Club at River Ranch at 221 Elysian Fields Drive,
Lafayette, Louisiana, 70508.

Despite our Mid-Continent asset divestiture, we never lost focus on
development of core assets in East Texas and the Gulf Coast. In June
of 2015, we initiated production from our single most impactful project
in the Company’s 30 year history - Thunder Bayou. The well’s initial
production rate of 41 MMcfe/d exceeded our original expectations and
today, after being online for more than 9 months, the well continues to
flow at 30 MMcfe/d, once again exceeding our expectations. We are
currently producing from the lower Cris R2 zone and are forecasting a
recompletion into the primary upper Cris R2 zone mid-year 2016.
This recompletion is expected to significantly increase the well’s
production rate, which will be the main contributor to our relatively
stable 2016 corporate production profile. Our Thunder Bayou and La
Cantera discoveries are two of the largest discoveries in Louisiana over
the last 10 years and are a testament to the talent of our Gulf Coast
team. These projects, with approximately 330 Bcfe of projected recoverable
reserves, should provide a stable long term cash flow profile with minimal
future maintenance capital. This is the funding engine for future growth.

Copies of the Company’s Annual Report on Form 10-K
may be obtained, without charge, by writing to our
Corporate Secretary at our Corporate Address or on the
Company’s website at www.petroquest.com.

COMMON STOCK LISTING

FORM 10-K

Listed on NYSE as PQ

2015 Annual Report

Letter To Shareholders

Dear Fellow Shareholders:

Charles T. Goodson
Chairman, President & CEO

Everyone has made their best guess about how long this downturn
will last. Instead of guessing, we took proactive steps to prepare for a
lower for longer commodity price scenario. We sold non-core assets in
the Mid-Continent, paid off all of our bank debt and closed on a private
exchange offer that lowered our debt profile, extended maturities and
substantially reduced annual fixed charges. In response to the lower
commodity price environment, our 2016 capital expenditure guidance
is approximately 70% less than 2015 showing our commitment to cost
control and liquidity preservation.

If there is a bright spot in the current commodity environment, we
believe it’s the future for natural gas. Domestic supply and demand
fundamentals are rapidly changing for the better. On the supply side of
the equation, the natural gas rig count is now below 100 rigs working,
off of the 2015 high seen in January at 329 gas rigs. As a result, we are
seeing natural gas production begin to roll over. Natural gas demand,
notwithstanding the mild winter, is increasing as natural gas is replacing
coal as a cleaner and more cost effective alternative for domestic power
generation, and U.S. liquefied natural gas (LNG) is now being exported
overseas. The first lower 48 U.S. LNG export ship left Cameron Parish,
Louisiana on February 24 to deliver its shipment to Brazil. This historic
event marks a new paradigm for the country in energy trade and allows
U.S. producers to compete for global demand.

Our 30 year history in the oil and gas business taught us how to
navigate turbulent markets. Success in a low price environment requires a
quality asset base, liquidity and a relentless commitment from a team to
recognize opportunities and preserve value. When prices recover, not only
will we bridge to the other side of this downturn, but return to a growth
path consistent with our execution over our long corporate history.

Significant Transactions

More recently in early 2016, we closed on a private exchange offer
of $214.4 million of our outstanding 10% Senior Notes due 2017 for
$53.6 million of cash, $144.6 million in aggregate principal of newly
issued 10% Second Lien Senior Secured Notes due 2021 and 4.2 million
shares of our common stock. The transaction extends the maturities of
a significant portion of our debt out to 2021, eliminates $70 million in
debt, and reduces our annual interest payments by $7 million a year.
In total, since the end of 2014, we have extinguished approximately
$145 million in debt. We estimate that the resulting reduction in interest
expense will provide an approximate $0.33/Mcfe improvement on 2016
cash margins.

Quality Assets

2015 Annual ReportIn the Cotton Valley, we have drilled a total of 20 horizontal wells with
each incremental well leading to improved performance and decreasing
well costs. Our most recent PQ #20 well was drilled and completed for
$3.9 million, a 43% decline in cost when compared to our wells that
were drilled in 2013. In addition, our PQ #20 well achieved a 24 hour
maximum production rate of 14.8 MMcfe/d, a 134% increase compared
to early vintage horizontal wells in 2011. Our Cotton Valley returns are
as competitive as any of the premier oil and gas trends in North America.
Just as we did in our Woodford assets, where we drove our spud through
completion time, pre-frac from 46 days to under 10 days, we are moving
quickly along the Cotton Valley learning curve. With state-of-the-art rigs
and engineering, our goal is to reduce cost so these properties achieve full
cycle returns that are proﬁtable below $2.00 per MMBtu. With low initial
decline production proﬁles and proximity to the Gulf Coast markets, we
believe this is a very realistic goal.

During 2015, the Company grew proved reserves by approximately 5%
as compared to proved reserves at December 31, 2014, proforma for the
Oklahoma divestment in June 2015. We ended 2015 with approximately
178 Bcfe of estimated proved oil and gas reserves which do not include
the unproved, behind pipe reserves associated with the Company’s four
producing wells at La Cantera and Thunder Bayou, estimated to total
approximately $60 million in additional PV-10 value at December 31, 2015.

This reserve growth, despite the continued decline in oil and gas prices
speaks volumes to the quality of our core assets in the Gulf Coast and
East Texas. Now that we have simpliﬁed our development strategy into our
two highest return and scalable assets, our Gulf Coast free cash ﬂow can
now be consistently directed to the development of the more than 600
identiﬁed Cotton Valley locations, which we expect will provide PetroQuest
a long-term growth platform.

Built For The Future

During any downturn, successful companies must adapt to endure. These
decisions are made by people. I truly believe an organization is only as
good as its people and I’m encouraged by the industry talent we’ve
been able to attract and retain. Our goal for 2016 is to survive. To that
end, we are evaluating additional liquidity building opportunities and
are ﬁercely implementing cost cutting initiatives. If we are in a lower for
longer scenario, like I said before, we’ve positioned PetroQuest and its
shareholders to weather the storm and realize signiﬁcant growth when
prices begin to recover.

Thank you for your continued support during these volatile times.

Sincerely,

Charles T. Goodson
Chairman, President and Chief Executive Ofﬁcer
March 18, 2016

PetroQuest Energy, Inc.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2015
or

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission File Number: 001-32681

PETROQUEST ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware

State of incorporation:

72-1440714

I.R.S. Employer Identification No.

400 E. Kaliste Saloom Road, Suite 6000
Lafayette, Louisiana 70508
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (337) 232-7028

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

Title of each class

Common Stock, par value $.001 per share

Name of each exchange on which registered

New York Stock Exchange

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

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

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

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

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 of this Form 10-K or any amendment to this
Form 10-K.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer

Accelerated filer

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes

The aggregate market value of the voting common equity held by non-affiliates of the registrant as of June 30, 2015, based on the $1.98 per share closing
price for the registrant's Common Stock, par value $.001 per share, as quoted on the New York Stock Exchange, was approximately $84,213,000 (for purposes
of this disclosure, the registrant assumed its directors, executive officers and beneficial owners of 5% or more of the registrant’s Common Stock were affiliates).

As of February 26, 2016, the registrant had outstanding 70,534,569 shares of Common Stock, par value $.001 per share.

Document incorporated by reference: portions of the definitive Proxy Statement of PetroQuest Energy, Inc. to be filed pursuant to Regulation 14A under
the Securities Exchange Act of 1934 with respect to the Annual Meeting of Stockholders to be held on May 18, 2016, which are incorporated by reference into
Part III of this Form 10-K.

Table of Contents

Page No.

Items 1 and 2 Business and Properties

PART I

Item 1A. Risk Factors

Item 1B. Unresolved Staff Comments

Item 3. Legal Proceedings

Item 4. Mine Safety Disclosures

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities

PART II

Item 6. Selected Financial Data

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Item 8. Financial Statements and Supplementary Data

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 9A. Controls and Procedures

Item 9B. Other Information

Item 10. Directors, Executive Officers and Corporate Governance

PART III

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accounting Fees and Services

Item 15. Exhibits, Financial Statement Schedules

PART IV

Index to Financial Statements

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this "Form 10-K") contains “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of
1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by
reference into this Form 10-K are forward looking statements. These forward-looking statements are subject to certain risks, trends
and uncertainties that could cause actual results to differ materially from those projected.

•

Among those risks, trends and uncertainties are:

the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014;

our indebtedness and the significant amount of cash required to service our indebtedness;

the effects of a financial downturn or negative credit market conditions on our liquidity, business and financial condition;

our ability to obtain adequate financing when the need arises to execute our long-term strategy and to fund our planned
capital expenditures;

limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions
imposed by our bank credit facility and restrictive debt covenants;

our ability to post additional collateral to satisfy our offshore decommissioning obligations:

losses or limits on potential gains resulting from hedging production;

our ability to find, develop, produce and acquire additional oil and natural gas reserves that are economically recoverable;

approximately 40% of our production being exposed to the additional risk of severe weather, including hurricanes and
tropical storms, as well as flooding, coastal erosion and sea level rise;

Securities and Exchange Commission (sometimes referred to herein as the "SEC") rules that could limit our ability to
book proved undeveloped reserves in the future;

the likelihood that our actual production, revenues and expenditures related to our reserves will differ from our estimates
of proved reserves;

regulatory initiatives relating to oil and natural gas development, hydraulic fracturing, and derivatives;

our ability to identify, execute or efficiently integrate future acquisitions;

the loss of key management or technical personnel;

ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices;

losses and liabilities from uninsured or underinsured drilling and operating activities;

our ability to market our oil and natural gas production;

changes in laws and governmental regulations, increases in insurance costs or decreases in insurance availability, and
delays in our offshore exploration and drilling activities that may result from the April 22, 2010 sinking of the Deepwater
Horizon and subsequent oil spill in the Gulf of Mexico;

proposed changes to U.S. tax laws;

competition from larger oil and natural gas companies;

the operating hazards attendant to the oil and gas business;

•

governmental regulation relating to hydraulic fracturing and environmental compliance costs and environmental
liabilities;

the operation and profitability of non-operated properties;

potential conflicts of interest resulting from ownership of working interests and overriding royalty interests in certain of
our properties by our officers and directors;

the loss of our information and computer systems;

the impact of terrorist activities on global economies;

the volatility of our stock price, and;

our ability to meet the continued listing standards of the New York Stock Exchange with respect to our common stock
or to cure any deficiency with respect thereto.

Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure

you that such expectations reflected in these forward looking statements will prove to have been correct.

When used in this Form 10-K, the words “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and
similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these
identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially
from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed
under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere
in this Form 10-K.

You should read these statements carefully because they discuss our expectations about our future performance, contain
projections of our future operating results or our future financial condition, or state other “forward-looking” information. You
should be aware that the occurrence of any of the events described under “Management’s Discussion and Analysis of Financial
Condition and Results of Operations,” “Risk Factors” and elsewhere in this Form 10-K could substantially harm our business,
results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common
stock could decline, and you could lose all or part of your investment.

We cannot guarantee any future results, levels of activity, performance or achievements. Except as required by law, we

undertake no obligation to update any of the forward-looking statements in this Form 10-K after the date of this Form 10-K.

As used in this Form 10-K, the words “we,” “our,” “us,” “PetroQuest” and the “Company” refer to PetroQuest Energy,
Inc., its predecessors and subsidiaries, except as otherwise specified. We have provided definitions for some of the oil and natural
gas industry terms used in this Form 10-K in “Glossary of Certain Oil and Natural Gas Terms” beginning on page 56.

Part I

Item 1 and 2. Business and Properties Items

Overview

PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with primary
operations in Texas, the Gulf Coast Basin and Oklahoma. We seek to grow our production, proved reserves, cash flow and earnings
at low finding and development costs through a balanced mix of exploration, development and acquisition activities. From the
commencement of our operations through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties
principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we
began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore
properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we
refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher
probability of success onshore wells and mitigate the risks associated with individual wells by expanding our drilling program
across multiple basins.

We have successfully diversified into onshore, longer life basins through a combination of selective acquisitions and
drilling activity, partially offset by our recent asset divestiture in Oklahoma as discussed below. As a result of our transition to
lower-risk, longer life basins, we have realized a 95% drilling success rate on 913 gross wells drilled over the last 10 years.
Comparing 2015 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by
254% and estimated proved reserves by 114%.

On June 4, 2015, we completed the sale of a majority of our interests in the Woodford and Mississippian Lime (the
“Oklahoma Divestiture”) for $280 million, subject to customary post-closing purchase price adjustments, effective January 1,
2015. At closing, we received $257.7 million in cash and recognized a receivable of $13.9 million, which was received in full
during the third quarter of 2015.

In connection with the sale, we entered into a Contract Operating Services Agreement whereby we will retain a minimal
working interest in the properties sold in the Oklahoma Divestiture and will provide certain services as a contract operator for a
period of one year from the closing date of the sale, subject to renewal for two additional one-year terms.

Balance Sheet Restructuring

In response to the decline in commodity prices that began in late 2014, and has continued throughout 2015 and into 2016,

we have initiated the following steps designed to enhance liquidity and reduce indebtedness:

• Consummated the Oklahoma Divestiture in June 2015 for approximately $280 million;

• Repaid all borrowings outstanding under our bank credit facility with a portion of the net proceeds from the Oklahoma

Divestiture;

• Reduced capital expenditures during 2015 by 67%, as compared to 2014;

• Approved a 2016 capital expenditure budget down 65% from 2015 spending;

• Completed an Exchange Offering (as described below) in February 2016 that reduced indebtedness by $69.7 million

and extended the maturity on $144.7 million of indebtedness from September 2017 to February 2021; and

• Announced plans to suspend the dividend on our Series B Preferred Stock beginning with the April 2016 payment,

which will save $5.1 million annually.

As a result of the actions outlined above, we have reduced our total indebtedness from $420.2 million at December 31,
2014 to $280.3 million as of the date of this report. Most recently, we completed a private exchange offering whereby participating
bondholders exchanged approximately $214.4 million of 10% Senior Notes due 2017 for approximately $53.6 million in cash,
approximately $144.7 million of our newly issued 10% Senior Secured Second Lien Notes due 2021 (the "10% senior secured
notes") and approximately 4.3 million shares of our common stock (the “Exchange Offering”). As a result of the Exchange Offering,
we reduced our annual fixed charges by $7 million and eliminated or extended the maturity date on 61% of our $350 million of
indebtedness as of December 31, 2015. After completion of the Exchange Offering, we have $280.3 million of total indebtedness,
with $135.6 million maturing in September 2017 and $144.7 million maturing in February 2021.

Business Strategy

Preserve Our Liquidity and Strengthen Our Balance Sheet. In response to the impact that the decline in commodity prices
has had on our cash flow, our 2016 capital expenditures will be significantly reduced as compared to 2015. Our 2016 capital
expenditures, which include capitalized interest and overhead but exclude acquisitions, are expected to range between $20 million
and $25 million, a 65% reduction at the midpoint of that range from our spending in 2015, and are expected to be funded through
cash flow from operations and cash on hand. Because we operate approximately 75% of our total estimated proved reserves and
manage the drilling and completion activities on an additional 13% of such reserves, we expect to be able to control the timing of
a substantial portion of our capital investments. We also may continue to opportunistically dispose of certain assets or enter into
joint venture arrangements to provide additional liquidity and plan to maintain our commodity hedging program, as in prior years.
In addition, we plan to suspend the quarterly dividend on our outstanding Series B Preferred Stock beginning with the dividend
payment due in April 2016 (which will save $5.1 million annually), reduce our cash costs by 25% from 2015 levels and consider
additional options to refinance our remaining $135.6 million of 10% Senior Notes due 2017.

Pursue Balanced Growth and Portfolio Mix. We plan to pursue a risk-balanced approach to the growth and stability of
our reserves, production, cash flows and earnings. Our goal is to strike a balance between lower risk development activities and

higher risk and higher impact exploration activities. While our reduced 2016 capital expenditure budget, combined with lower
commodity prices, is expected to impact our near-term growth outlook, we plan to allocate our capital investments in a manner
that continues to geographically and operationally diversify our asset base. Through our portfolio diversification efforts, at
December 31, 2015, approximately 75% of our estimated proved reserves were located in longer life and lower risk basins in
Oklahoma and Texas and 25% were located in the shorter life, but higher flow rate reservoirs in the Gulf Coast Basin. In terms
of production diversification, during 2015, 60% of our production was derived from longer life basins. Our 2015 production was
comprised of 75% natural gas, 9% oil and 16% natural gas liquids.

Target Underexploited Properties with Substantial Opportunity for Upside. We plan to maintain a rigorous prospect
selection process that enables us to leverage our operating and technical experience in our core operating areas. In evaluating these
prospects, we seek properties that provide sufficient acreage for future exploration and development, as well as properties that
may benefit from the latest exploration, drilling, completion and operating techniques to more economically find, produce and
develop oil and gas reserves.

Concentrate in Core Operating Areas and Build Scale. We plan to continue focusing on our operations in Texas and the
Gulf Coast Basin. Operating in concentrated areas helps to better control our overhead by enabling us to manage a greater amount
of acreage with fewer employees and minimize incremental costs of increased drilling and production. We have substantial
geological and reservoir data, operating experience and partner relationships in these regions. We believe that these factors,
combined with the existing infrastructure and favorable geologic conditions with multiple known oil and gas producing reservoirs
in these regions, will provide us with attractive investment opportunities.

Manage Our Risk Exposure. We plan to continue several strategies designed to mitigate our operating risks. We have
adjusted the working interest we are willing to hold based on the risk level and cost exposure of each project. For example, we
typically reduce our working interests in higher risk exploration projects while retaining greater working interests in lower risk
development projects. Our partners often agree to pay a disproportionate share of drilling costs relative to their interests, allowing
us to allocate our capital spending to maximize our return and reduce the inherent risk in exploration and development activities.
We also strive to retain operating control of the majority of our properties to control costs and timing of expenditures and we
expect to continue to actively hedge a portion of our future planned production to mitigate the impact of commodity price fluctuations
and achieve more predictable cash flows. We may also enter into joint venture arrangements designed to develop our properties
while limiting our capital requirements and preserving our liquidity.

2015 Financial and Operational Summary

During 2015, we invested $64.6 million in exploratory, development and acquisition activities. We drilled 29 gross
exploratory wells and 27 gross development wells realizing an overall success rate of 95%. These activities were financed through
our cash flow from operations and proceeds from the Oklahoma Divestiture. During 2015, our production decreased 21% to 34.2
Bcfe as a result of the Oklahoma Divestiture and normal production declines at our Gulf Coast fields. Our estimated proved
reserves at December 31, 2015 decreased 55% from 2014 as discussed in greater detail below.

Oil and Gas Reserves

Our estimated proved reserves at December 31, 2015 decreased 55% from 2014 totaling 1.8 MMBbls of oil, 34.8 Bcfe
of natural gas liquids (Ngls) and 132 Bcf of natural gas, with a pre-tax present value, discounted at 10%, of the estimated future
net revenues based on average prices during 2015 (“PV-10”) of $127.7 million. The decrease in our estimated proved reserves
during 2015 was primarily the result of the Oklahoma Divestiture, which represented 227.2 Bcfe of our estimated proved reserves
as of December 31, 2014 with $248.9 million of PV-10. At December 31, 2015, our standardized measure of discounted cash
flows, which includes the estimated impact of future income taxes, totaled $127.7 million. See the reconciliation of PV-10 to the
standardized measure of discounted cash flows below. Our PV-10 and standardized measure of discounted cash flows utilized
prices (adjusted for field differentials) for the years ended December 31, 2015 and 2014 as follows:

Oil per Bbl

Natural gas per Mcf

Ngl per Mcfe

12/31/2015 12/31/2014

$50.29

$96.45

$2.41

$2.24

$3.80

$4.11

Ryder Scott Company, L.P., a nationally recognized independent petroleum engineering firm, prepared the estimates of
our proved reserves and future net cash flows (and present value thereof) attributable to such proved reserves at December 31,
2015. Our internal reservoir engineering staff is managed by an individual with 34 years of industry experience as a reservoir and
production engineer, including thirteen years as a reservoir engineering manager with PetroQuest. This individual is responsible
for overseeing the estimates prepared by Ryder Scott.

Our internal controls that are used in our reserve estimation process are designed to provide reasonable assurance that
our reserve estimates are computed and reported in accordance with SEC rules and regulations and GAAP. These internal controls
are regularly tested in connection with our annual assessment of internal controls over financial reporting and include:

•

Utilizing documented process workflows;

Employing qualified professional engineering, geological, land, financial and marketing personnel; and

Providing continuing education and training for all personnel involved in our reserve estimation process.

Each quarter, our Reservoir Engineering Manager presents the status of the changes to our reserve estimates to our
executive team, including our Chief Executive Officer. These reserve estimates are then presented to our Board of Directors in
connection with quarterly meetings. In addition, our reserve booking policies and procedures are reviewed annually by one of
the members of our Board of Directors, acting on behalf of our Audit Committee.

With respect to proved undeveloped reserves (“PUD reserves”), we maintain a five year development plan that is updated
and approved annually by our PUD Review Committee (as described below) with input from our executive team and asset managers
and reviewed quarterly by our executive team and asset managers. Our development plan includes only PUDs that we are reasonably
certain will be drilled within five years of booking based upon qualitative and quantitative factors including estimated risk-based
returns, current pricing forecasts, recent drilling results, availability of services, equipment and personnel, seasonal weather patterns
and changes in drilling and completion techniques and technology. Our PUD reserves are based upon our substantial basin-specific
technical and operating experience relative to the location of the reserves. Over the last five years, we have realized a 96% drilling
success rate on 28 gross wells drilled in East Texas where 95% of our PUD reserves are currently booked. Furthermore, because
all of our longer life, onshore PUD reserves (100% of total PUD reserve volumes at December 31, 2015) are direct offsetting
locations to producing wells, we have comprehensive data available, which enables us to forecast economic results, including
drilling and operating costs, with reasonable certainty.

During 2014 we established a committee that annually reviews our PUD reserves. Our PUD Review Committee (the
“Committee”) is comprised of our Executive Vice President of Operations, Chief Financial Officer and Reservoir Engineering
Manager and meets annually in connection with each year-end reserve report. The Committee is responsible for reviewing all
PUD locations, not only in terms of technical and financial merits as reviewed by our independent petroleum engineering firm,
but also to apply a robust evaluation of the timing and reasonable certainty of the development plan in light of all known
circumstances including our budget, the outlook for commodity prices and the location of ongoing drilling programs. The
Committee’s evaluation of reasonable certainty of the development plan includes a thorough assessment of near term drilling plans
to develop PUDs, a review of adherence to previously adopted development plans and a review of historical PUD conversion
rates.

The following table sets forth certain information about our estimated proved reserves as of December 31, 2015:

Proved Developed
Proved Undeveloped
Total Proved

Oil (MBbls) NGL (Mmcfe)
15,792
19,034
34,826

1,549
257
1,806

Natural Gas
(Mmcf)

78,533
53,811
132,344

Total Mmcfe*
103,615
74,389
178,004

Oil conversion to Mcfe at one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

As of December 31, 2015, our PUD reserves totaled 74.4 Bcfe, a 53% decrease from our PUD reserves at December 31,
2014. This decrease was primarily due to the sale of PUDs associated with the Oklahoma Divestiture. During 2015, we spent
$8.7 million converting 23 Bcfe of PUD reserves at December 31, 2014 to proved developed reserves at December 31, 2015. In
addition, at December 31, 2015, we had five wells in progress that are estimated to convert 9 Bcfe of PUD reserves in 2016.

The following table presents an analysis of the change in our PUD reserves from December 31, 2014 to December 31, 2015:

PUD Reserve balance at December 31, 2014
PUD reserves converted to proved developed
PUD reserves added from extensions, discoveries and revisions
PUD reserves sold
PUD Reserve balance at December 31, 2015

MMcfe

159,460
(22,983)
29,190
(91,278)
74,389

Approximately 5% and 95% of our PUD reserves at December 31, 2015 were associated with the future development of
our Oklahoma and East Texas properties, respectively. We expect all of our PUD reserves at December 31, 2015 to be developed
over the next five years. However, our PUD reserve inventory does not encompass all drilling activities over the next five years.
For example, during 2015 we spent $20.5 million converting 25.4 Bcfe of reserves that were classified as probable reserves at
December 31, 2014 to proved developed producing at December 31, 2015 and therefore were not included in the above table. We
expect to continue to allocate capital to projects that do not have proved reserves ascribed to them. At December 31, 2015, we had
no PUD reserves booked for longer than five years. Estimated future costs related to the development of PUD reserves are expected
to total $3.1 million in 2016, $21.7 million in 2017, $5.2 million in 2018, $20.4 million in 2019 and $18.5 million in 2020.

The estimated cash flows from our proved reserves at December 31, 2015 were as follows:

Estimated pre-tax future net cash flows (1)
Discounted pre-tax future net cash flows (PV-10) (1)
Total standardized measure of discounted future net cash flows

$
$

141,208
111,874

$
$

58,357
15,811

Proved Developed
(M$)

Proved
Undeveloped
(M$)

Total Proved
(M$)

$
$
$

199,565
127,685
127,685

(1) Estimated pre-tax future net cash flows and discounted pre-tax future net cash flows (PV-10) are non-GAAP measures
because they exclude income tax effects. Management believes these non-GAAP measures are useful to investors as they
are based on prices, costs and discount factors which are consistent from company to company, while the standardized
measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. As a
result, the Company believes that investors can use these non-GAAP measures as a basis for comparison of the relative
size and value of the Company’s reserves to other companies. The Company also understands that securities analysts and
rating agencies use these non-GAAP measures in similar ways.

The following table reconciles undiscounted and discounted future net cash flows to standardized measure of discounted

cash flows as of December 31, 2015:

Estimated pre-tax future net cash flows
10% annual discount
Discounted pre-tax future net cash flows
Future income taxes discounted at 10%
Standardized Measure of discounted future net cash flows

Total Proved (M$)

199,565
(71,880)
127,685
—
127,685

We have not filed any reports with other federal agencies that contain an estimate of total proved net oil and gas reserves.

Core Areas

The following table sets forth estimated proved reserves and annual production from each of our core areas (in Bcfe) for

the years ended December 31, 2015 and 2014.

East Texas
Gulf Coast Basin
Oklahoma Woodford (1)
Other

2015

2014

Reserves

Production

Reserves

Production

114.1
43.9
20.0
—
178.0

11.1
13.8
9.2
0.1
34.2

89.4
55.1
252.4
0.2
397.1

9.7
16.3
16.9
0.4
43.3

(1) On June 4, 2015, we completed the Oklahoma Divestiture (representing 227.2 Bcfe of proved reserves at December 31,
2014) which contributed 7.0 Bcfe and 16.4 Bcfe of production in 2015 and 2014, respectively.

Oklahoma - Woodford

During 2015, we drilled and participated in 49 gross wells, achieving a 100% success rate. In total, we invested $13.2
million during 2015 acquiring prospective acreage and drilling and completing wells. Average daily production from our Oklahoma
properties during 2015 totaled 25 MMcfe per day, a 45% decrease from 2014 average daily production primarily as a result of the
Oklahoma Divestiture. We added approximately 17 Bcfe of estimated proved reserves from our drilling program during the year,
but sold 239 Bcfe resulting in a 92% decrease in our estimated proved reserves. Other than capital required to convert PUDs in
progress at the end of 2015, we have not allocated capital from our 2016 budget to operations in the Woodford Shale due to low
commodity prices.

East Texas

During 2015, we invested $22.1 million in our East Texas properties where we drilled four gross wells, achieving a 100%
success rate. Net production from our East Texas assets averaged 30.4 MMcfe per day during 2015, a 15% increase from 2014
average daily production and our estimated proved reserves increased 28% from 2014, as a result of successful drilling in our
Carthage field. We have allocated approximately 33% of our 2016 capital budget to converting one PUD location and performing
various re-completions and plugging and abandonment operations at our Carthage field.

Gulf Coast Basin

During 2015, we invested $34.1 million in this area including $6.1 million related to our Fleetwood joint venture and
$17.0 million for the Thunder Bayou discovery which started producing in the second quarter of 2015. We also drilled three
unsuccessful wells in this area in 2015. Production from this area decreased 15% from 2014 totaling 37.8 MMcfe per day in 2015
due to normal production declines in the Gulf Coast area and a pipeline shut-in during the fourth quarter of 2015. Our estimated
proved reserves in this area decreased 20% from 2014 primarily as a result of the 13.8 Bcfe of current year production, offset by
reserves from our Thunder Bayou discovery. We have allocated approximately 67% of our 2016 capital budget to performing
various re-completions and plugging and abandonment projects in the Gulf Coast Basin.

Markets and Customers

We sell our oil and natural gas production under fixed or floating market contracts. Customers purchase all of our oil and
natural gas production at current market prices. The terms of the arrangements generally require customers to pay us within 30
days after the production month ends. As a result, if the customers were to default on their payment obligations to us, near-term
earnings and cash flows would be adversely affected. However, due to the availability of other markets and pipeline connections,
we do not believe that the loss of these customers or any other single customer would adversely affect our ability to market
production. Our ability to market oil and natural gas from our wells depends upon numerous factors beyond our control, including:

•

the extent of domestic production and imports of oil and natural gas;

the proximity of the natural gas production to pipelines;

the availability of capacity in such pipelines;

the demand for oil and natural gas by utilities and other end users;

•

the availability of alternative fuel sources;

the effects of inclement weather;

state and federal regulation of oil and natural gas production; and

federal regulation of gas sold or transported in interstate commerce.

We cannot assure you that we will be able to market all of the oil or natural gas we produce or that favorable prices can

be obtained for the oil and natural gas we produce.

In view of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products,
we are unable to predict future oil and natural gas prices and demand or the overall effect such prices and demand will have on
the Company. During 2015, one customer accounted for 21%, one accounted for 18%, one accounted for 17% and one accounted
for 10% of our oil and natural gas revenue. During 2014, one customer accounted for 30%, one accounted for 24% and one
accounted for 14% of our oil and natural gas revenue. During 2013, one customer accounted for 35% and two accounted
for 14% each of our oil and natural gas revenue. These percentages do not consider the effects of commodity hedges. We do not
believe that the loss of any of our oil or natural gas purchasers would have a material adverse effect on our operations due to the
availability of other purchasers.

Production, Pricing and Production Cost Data

The following table sets forth our production, pricing and production cost data during the periods indicated. Two of our
core areas, Gulf Coast Basin and East Texas, represented approximately 15% or more of our total estimated proved reserves at
December 31, 2015.

Year Ended December 31,
2014

2013

2015

Production:
Oil (Bbls):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Oil (Bbls)
Gas (Mcf):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Gas (Mcf)
NGL (Mcfe):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total NGL (Mcfe)
Total Production (Mcfe):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Production (Mcfe)
Average sales prices (1):
Oil (per Bbl):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Oil (per Bbl)
Gas (per Mcf)
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Gas (per Mcf)
NGL (per Mcfe)
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total NGL (per Mcfe)
Total Per Mcfe:
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Per Mcfe

473,846
50,739
1,274
2,670
528,529

9,421,031
7,838,144
8,231,131
11,545
25,501,851

1,548,228
2,946,185
985,838
6,988
5,487,239

13,812,335
11,088,763
9,224,613
34,553
34,160,264

687,855
62,013
423
52,218
802,509

10,825,424
6,636,174
13,468,244
97,829
31,027,671

1,325,288
2,672,885
3,398,750
85,387
7,482,310

16,277,842
9,681,137
16,869,532
496,524
43,325,035

48.94
48.28
52.26
50.23
48.89

96.71
92.21
97.04
95.74
96.30

2.55
2.63
1.75
3.17
2.32

3.03
1.94
3.49
3.94
2.53

3.76
2.60
1.94
5.74
2.89

4.38
4.08
3.27
4.04
3.83

6.00
4.17
3.63
5.55
4.27

7.49
4.54
3.34
11.82
5.26

512,041
82,500
971
85,468
680,980

9,876,771
4,123,416
15,055,601
170,055
29,225,843

1,312,995
1,333,725
1,971,376
136,127
4,754,223

14,262,012
5,952,141
17,032,803
818,990
38,065,946

105.74
98.61
90.52
97.59
103.83

3.70
3.73
2.25
3.54
2.95

7.12
4.70
4.31
5.21
5.22

7.02
5.00
2.49
11.79
4.78

Average Production Cost per Mcfe (2):
Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other
Total Average Production Cost per Mcfe

(1) Does not include the effect of hedges.
(2) Production costs do not include production taxes.

Oil and Gas Producing Wells

Year Ended December 31,
2014

2013

2015

1.86
0.90
0.45
8.69
1.17

1.59
1.21
0.52
4.56
1.12

1.60
1.47
0.47
5.03
1.15

The following table details the productive wells in which we owned an interest as of December 31, 2015:

Gross

Net

Productive Wells:

Oil:

Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other

Gas:

Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other

Total

7
—
1
—
8

15
98
392
—
505
513

2.86
—
0.03
—
2.89

7.94
65.09
101.32
—
174.35
177.24

Of the 513 gross productive wells at December 31, 2015, one had dual completions.

Oil and Gas Drilling Activity

The following table sets forth the wells drilled and completed by us during the periods indicated. All wells were drilled

in the continental United States.

2015

2014

2013

Gross

Net

Gross

Net

Gross

Net

Exploration:

Productive:

Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other

Non-productive:

Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other

Total
Development:

Productive:

Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other

Non-productive:

Gulf Coast Basin
East Texas
Oklahoma - Woodford
Other

Total

—
4
22
—
26

3
—
—
—
3
29

—
—
27
—
27

—
—
—
—
—
27

—
3.31
5.05
—
8.36

1.22
—
—
—
1.22
9.58

—
—
4.30
—
4.30

—
—
—
—
—
4.30

2
4
15
4
25

2
—
—
2
4
29

—
2
24
2
28

—
—
1
—
1
29

1.19
3.10
6.58
0.56
11.43

1.12
—
—
2.00
3.12
14.55

—
1.55
5.86
0.19
7.60

—
—
0.50
—
0.50
8.10

1
1
22
7
31

3
—
—
2
5
36

1
—
3
—
4

—
—
—
—
—
4

0.94
0.99
5.66
2.11
9.70

0.62
—
—
0.62
1.24
10.94

0.24
—
1.36
—
1.60

—
—
—
—
—
1.60

At December 31, 2015, we had 7 gross (1.80 net) wells in progress.

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of

December 31, 2015:

Kansas
Louisiana
Mississippi
Oklahoma
Texas
Federal Waters
Total

Leasehold Acreage

Developed

Undeveloped

Gross

Net

Gross

Net

—
4,833
721
59,698
40,864
51,639
157,755

—
2,002
721
21,900
21,534
32,450
78,607

2,563
8,241
—
277
7,285
7,124
25,490

1,282
3,161
—
87
4,222
7,124
15,876

Leases covering 17% of our net undeveloped acreage are scheduled to expire in 2016, 9% in 2017, 9% in 2018 and 65%
thereafter. At December 31, 2015, we do not have any PUD reserves attributed to acreage that has an expiration date preceding
the scheduled date for initial development. Of the acreage subject to leases scheduled to expire during 2016, 57% relates to
undeveloped acreage in the Fleetwood area in South Louisiana where we are currently evaluating future plans.

Title to Properties

Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due
and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties
or from the respective interests therein or materially interfere with their use in the operation of the business.

As is customary in the industry, other than a preliminary review of local records, little investigation of record title is made
at the time of acquisitions of undeveloped properties. Investigations, which generally include a title opinion of outside counsel,
are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations
on undeveloped properties. Our properties are typically subject, in one degree or another, to one or more of the following:

•

royalties and other burdens and obligations, express or implied, under oil and gas leases;

overriding royalties and other burdens created by us or our predecessors in title;

a variety of contractual obligations (including, in some cases, development obligations) arising under operating
agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their
titles;

back-ins and reversionary interests existing under purchase agreements and leasehold assignments;

liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to
unpaid suppliers and contractors and contractual liens under operating agreements; pooling, unitization and
communitization agreements, declarations and orders; and

•

easements, restrictions, rights-of-way and other matters that commonly affect property.

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account
in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and
obligations affecting our properties are conventional in the industry for properties of the kind that we own.

Federal Regulations

Sales and Transportation of Natural Gas. Historically, the transportation and sales for resale of natural gas in interstate
commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 and the
Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol
Act deregulated the price for all “first sales” of natural gas. Thus, all of our sales of gas may be made at market prices, subject to
applicable contract provisions. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. Since
1985, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers
on an open-access, non-discriminatory basis. We cannot predict what further action the FERC will take on these matters. Some
of the FERC's more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation
service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other
natural gas producers, gatherers and marketers with which we compete.

The Outer Continental Shelf Lands Act (the “OCSLA”), which was administered by the Bureau of Ocean Energy
Management, Regulation and Enforcement (the “BOEMRE”) and, after October 1, 2011, its successors, the Bureau of Ocean
Energy Management (the “BOEM”) the Bureau of Safety and Environmental Enforcement (the “BSEE”), and the FERC, requires
that all pipelines operating on or across the shelf provide open-access, non-discriminatory service. There are currently no regulations
implemented by the FERC under its OCSLA authority on gatherers and other entities outside the reach of its NGA jurisdiction.
Therefore, we do not believe that any FERC, BOEM or BSEE action taken under OCSLA will affect us in a way that materially
differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

Our natural gas sales are generally made at the prevailing market price at the time of sale. Therefore, even though we
sell significant volumes to major purchasers, we believe that other purchasers would be willing to buy our natural gas at comparable
market prices.

Natural gas continues to supply a significant portion of North America's energy needs and we believe the importance of
natural gas in meeting this energy need will continue. The impact of the sudden drop in crude oil prices has not yet had a significant
impact on gas prices, but a continued drop in crude oil prices could eventually impact gas markets. At this time, we are not in a
position to predict the scope of any loss of market due to lower crude oil prices.

On August 8, 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. This comprehensive act contains
many provisions that intended to encourage oil and gas exploration and development in the U.S. The 2005 EPA directs the FERC,
BOEM and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends
the NGA to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as us, to use any deceptive
or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation
services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC
issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject
to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any
entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material
fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice
that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to
intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the
extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It
therefore reflects a significant expansion of the FERC's enforcement authority. To date, we do not believe we have been, nor do
we anticipate we will be affected any differently than other producers of natural gas.

In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent
orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical
natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural
gas processors and natural gas marketers are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes
of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may
contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions
should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our
administrative costs. To date, we do not believe we have been, nor do we anticipate that we will be affected any differently than
other producers of natural gas.

Sales and Transportation of Crude Oil. The spot markets for oil, gas and NGLs are subject to volatility and supply and
demand factors fluctuations. Our sales of crude oil, condensate and natural gas liquids are not currently regulated, and are subject
to applicable contract provisions made at market prices and typically under short term agreements with third parties. Additionally,
we may periodically enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil, gas
or natural gas liquids production. In a number of instances, however, the ability to transport and sell such products is dependent
on pipelines whose rates, terms and conditions of service are subject to the FERC's jurisdiction under the Interstate Commerce
Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions
of service are subject to regulation by state regulatory bodies under state statutes.

The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed
than the FERC's regulation of gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate, and natural
gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate
pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based,
although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561,
pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in
the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels
provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline
and the rate resulting from application of the index. A pipeline can seek to charge market based rates if it establishes that it lacks
significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers.
A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding,
or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline.

Federal Leases. We maintain operations located on federal oil and natural gas leases, which are administered by the
BOEM or the BSEE, pursuant to the OCSLA. The BOEM and the BSEE regulate offshore operations, including engineering and
construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Gulf of Mexico
shelf, and removal of facilities.

The BOEM handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and
development plans, renewable energy development, NEPA analysis and environmental studies, and the BSEE is responsible for
the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and
15

environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore
regulatory programs, oil spill response and newly formed training and environmental compliance programs. Our federal oil and
natural gas leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require
compliance with detailed regulations and orders that are subject to interpretation and change by the BOEM or BSEE. We are
currently subject to regulations governing the plugging and abandonment of wells located offshore and the installation and removal
of all production facilities, structures and pipelines, and the BOEM or the BSEE may in the future amend these regulations. Please
read “Risk Factors” beginning on page 20 for more information on new regulations.

To cover the various obligations of lessees on the Outer Continental Shelf (the “OCS”), the BOEM and the BSEE generally
require that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied.
While we have been exempt from such supplemental bonding requirements in the past, beginning in 2014 we were required to
post supplemental bonding or alternate form of collateral for certain of our offshore properties. We have been able to satisfy the
collateral requirements using a combination of our existing cash on hand and the issuance of supplemental bonds. The cost of
compliance with these supplemental bonding requirements has not been material. Under some circumstances, the BOEM may
require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially
adversely affect our financial condition and results of operations. As a result of certain bankruptcies of Gulf of Mexico operations,
BSEE and BOEM are currently reassessing decommissioning liability and supplemental bonding requirements for all operations
on the GOM OCS with respect to decommissioning wells and platforms in the Gulf of Mexico and are updating all decommissioning
costs in the Gulf of Mexico. The Department of the Interior through the BOEM and BSEE have made enforcement of
decommissioning liabilities one of its top priorities. Recent DOI guidance has indicated that well abandonment and
decommissioning requirements are not necessarily tied to lease termination. Based on the ongoing review of such decommissioning
and abandonment costs, the Company’s potential liability for such costs has become more expensive and as a result supplemental
bonding costs may continue to increase, which along with any future directives or changes to BOEM’s current supplemental
bonding requirements, could materially and adversely affect our financial condition, cash flows, and results of operations. Because
we are not exempt from the BOEM’s supplemental bonding requirements, we engage a number of surety companies to post the
requisite bonds. Pursuant to the terms of our agreements with these surety companies, we are required to post collateral at the
outset of the agreement or subsequently on demand, the amount of which typically may be increased at the surety companies’
discretion. Two of our surety companies recently requested that we post collateral to support certain of the bonds that are issued
on our behalf. We are currently evaluating various options for posting the requested collateral, however, given the effect of current
commodity prices on our creditworthiness and the unwillingness of the surety companies to post bonds without the requisite
collateral, we cannot assure you that we will be able to satisfy current or future demands for collateral for the requisite bonds or
comply with new supplemental bonding requirements. If we fail to do so, we may be in default under our agreements with the
surety companies, which in turn could cause a cross-default under our bank credit facility and potentially the indenture governing
our 10% senior secured notes.

In addition, we may be required to provide cash collateral or letters of credit to support the issuance of such bonds or
other surety. Such letters of credit would likely be issued under our bank credit facility and would reduce the amount of borrowings
available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can
continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our bank credit facility to
support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested,
the BOEM may require any of our operations on federal leases to be suspended, canceled or otherwise impose monetary penalties,
and one or more of such actions could have a material adverse effect on our business, prospects, results of operations, financial
condition, and liquidity.

Hurricanes in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS. The effects from
past hurricanes have included structural damage to pipelines, wells, fixed production facilities, semi-submersibles and jack-up
drilling rigs. The BOEM and the BSEE will continue to be concerned about the loss of these facilities and rigs as well as the
potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the
potential for future damage, the BOEMRE historically issued guidance aimed at improving platform survivability by taking into
account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not
more stringent, requirements will be issued by the BOEM or the BSEE for future hurricane seasons. New requirements, if any,
could increase our operating costs due to future storms.

The Office of Natural Resources Revenue (the “ONRR”) in the U.S. Department of the Interior administers the collection
of royalties under the terms of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is
based upon the terms of the oil and natural gas leases as well as the regulations promulgated by the ONRR.

Federal, State or American Indian Leases. In the event we conduct operations on federal, state or American Indian oil
and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes,

and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits
issued by the Bureau of Land Management (“BLM”) or the BOEM or other appropriate federal or state agencies.

The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore
oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such
restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds
a federal onshore oil and gas lease. If this restriction is violated, the corporation's lease can be cancelled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for
agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous
federal onshore oil and gas leases. It is possible that holders of our equity interests may be citizens of foreign countries, which at
some time in the future might be determined to be non-reciprocal under the Mineral Act.

State Regulations

Most states regulate the production and sale of oil and natural gas, including:

•

requirements for obtaining drilling permits;

the method of developing new fields;

the spacing and operation of wells;

the prevention of waste of oil and gas resources; and

the plugging and abandonment of wells.

The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may

be established on a market demand or conservation basis or both.

We may enter into agreements relating to the construction or operation of a pipeline system for the transportation of
natural gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in
certain instances, be subject to the jurisdiction of such state’s administrative authority charged with the responsibility of regulating
intrastate pipelines. In such event, the rates that we could charge for gas, the transportation of gas, and the construction and
operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative
authority.

Legislative Proposals

In the past, Congress has been very active in the area of natural gas regulation. New legislative proposals in Congress
and the various state legislatures, if enacted, could significantly affect the petroleum industry. At the present time it is impossible
to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any,
such proposals might have on our operations.

Environmental Regulations

General. Our activities are subject to existing federal, state and local laws and regulations governing environmental
quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary
event, compliance with existing federal, state and local laws, regulations and rules regulating the release of materials into the
environment or otherwise relating to the protection of human health, safety and the environment will not have a material effect
upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot
predict what effect additional regulation or legislation, enforcement policies, and claims for damages to property, employees, other
persons and the environment resulting from our operations could have on our activities.

Our activities with respect to exploration and production of oil and natural gas, including the drilling of wells and the
operation and construction of pipelines and other facilities for extracting, transporting or storing natural gas and other petroleum
products, are subject to stringent environmental regulation by state and federal authorities, including the United States
Environmental Protection Agency (the “USEPA”). Such regulation can increase the cost of planning, designing, installing and
operating such facilities. Although we believe that compliance with environmental regulations will not have a material adverse
effect on us, risks of substantial costs and liabilities are inherent in oil and gas production operations, and there can be no assurance
that significant costs and liabilities will not be incurred. Moreover it is possible that other developments, such as spills or other

unanticipated releases, stricter environmental laws and regulations, and claims for damages to property or persons resulting from
oil and gas production, would result in substantial costs and liabilities to us.

Solid and Hazardous Waste. We own or lease numerous properties that have been used for production of oil and gas
for many years. Although we have utilized operating and disposal practices standard in the industry at the time, hydrocarbons or
solid wastes may have been disposed or released on or under these properties. In addition, many of these properties have been
operated by third parties that controlled the treatment of hydrocarbons or solid wastes and the manner in which such substances
may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become
stricter over time. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes
disposed or released by prior owners or operators) or property contamination (including groundwater contamination by prior
owners or operators) or to perform remedial plugging operations to prevent future contamination.

We generate wastes, including hazardous wastes, which are subject to regulation under the federal Resource Conservation
and Recovery Act (“RCRA”) and state statutes. The USEPA has limited the disposal options for certain hazardous wastes.
Furthermore, it is possible that certain wastes generated by our oil and gas operations which are currently exempt from regulation
as “hazardous wastes” may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes, and
therefore be subject to more rigorous and costly disposal requirements.

Naturally Occurring Radioactive Materials (“NORM”) are radioactive materials which precipitate on production
equipment or area soils during oil and natural gas extraction or processing. NORM wastes are regulated under the RCRA framework,
although such wastes may qualify for the oil and gas hazardous waste exclusion. Primary responsibility for NORM regulation
has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste;
management of waste piles, containers and tanks; and limitations upon the release of NORM-contaminated land for unrestricted
use. We believe that our operations are in material compliance with all applicable NORM standards.

Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known
as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with
respect to the release or threatened release of a “hazardous substance” into the environment. These persons include the owner and
operator of a site and persons that disposed or arranged for the disposal of hazardous substances at a site. CERCLA also authorizes
the USEPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to
seek to recover from the responsible persons the costs of such action. State statutes impose similar liability.

Under CERCLA, the term “hazardous substance” does not include “petroleum, including crude oil or any fraction thereof,”
unless specifically listed or designated and the term does not include natural gas, natural gas liquids, liquefied natural gas, or
synthetic gas usable for fuel. While this “petroleum exclusion” lessens the significance of CERCLA to our operations, we may
generate waste that may fall within CERCLA's definition of a “hazardous substance” in the course of our ordinary operations. We
also currently own or lease properties that for many years have been used for the exploration and production of oil and natural
gas. Although we and, to our knowledge, our predecessors have used operating and disposal practices that were standard in the
industry at the time, “hazardous substances” may have been disposed or released on, under or from the properties owned or leased
by us or on, under or from other locations where these wastes have been taken for disposal. At this time, we do not believe that
we have any liability associated with any Superfund site, and we have not been notified of any claim, liability or damages under
CERCLA.

Endangered Species Act. Federal and state legislation including, in particular, the federal Endangered Species Act of
1973 (“ESA”), impose requirements to protect imperiled species from extinction by conserving and protecting threatened and
endangered species and the habitat upon which they depend. With specified exceptions, the ESA prohibits the “taking,” including
killing, harassing or harming, of any listed threatened or endangered species, as well as any degradation or destruction of its habitat.
In addition, the ESA mandates that federal agencies carry out programs for conservation of listed species. Many state laws similarly
protect threatened and endangered species and their habitat. We operate in areas in which listed species may be present. For
example, the American Burying Beetle, listed in 1989 as endangered, is present in regions overlying the Woodford Shale in
Oklahoma. As a result, we may be required to adopt protective measures, obtain incidental take permits, and otherwise adjust our
drilling plans to comply with ESA requirements.

Oil Pollution Act. The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of requirements
on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States
waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which
an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and
private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill
was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating
regulations. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses
exist to the liability imposed by the OPA.

The OPA establishes a liability limit for onshore facilities of $350 million and for offshore facilities of all removal costs
plus $33.65 million, and lesser limits for some vessels depending upon their size. Effective December 2015, the Coast Guard has
increased the liability limit for onshore facilities to $633.8 million based on an inflation adjustment. The regulations promulgated
under OPA impose proof of financial responsibility requirements that can be satisfied through insurance, guarantee, indemnity,
surety bond, letter of credit, qualification as a self-insurer, or a combination thereof. The amount of financial responsibility required
depends upon a variety of factors including the type of facility or vessel, its size, storage capacity, oil throughput, proximity to
sensitive areas, type of oil handled, history of discharges and other factors. We carry insurance coverage to meet these obligations,
which we believe is customary for comparable companies in our industry. A failure to comply with OPA's requirements or inadequate
cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.

As a result of the explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico in 2010, Congress
considered but did not enact legislation that would eliminate the current cap on liability for damages and increase minimum levels
of financial responsibility under OPA. If enacted, such legislation could increase our obligations and potential liability, but adoption
of such legislation is uncertain. We are not aware of the occurrence of any action or event that would subject us to liability under
OPA, and we believe that compliance with OPA's financial responsibility and other operating requirements will not have a material
adverse effect on us.

Discharges. The Clean Water Act (“CWA”) regulates the discharge of pollutants to waters of the United States, including
wetlands, and requires a permit for the discharge of pollutants, including petroleum, to such waters. The CWA also requires a
permit for the discharge of dredged or fill material into wetlands. A revised regulatory definition of “Waters of the United States”
that would expand requirements for CWA permitting, has been promulgated, but these regulations have been stayed pending the
outcome of judicial challenges. Certain facilities that store or otherwise handle oil are required to prepare and implement Spill
Prevention, Control and Countermeasure Plans and Facility Response Plans relating to the possible discharge of oil to surface
waters. We are required to prepare and comply with such plans and to obtain and comply with discharge permits. We believe we
are in substantial compliance with these requirements and that any noncompliance would not have a material adverse effect on
us. The CWA also prohibits spills of oil and hazardous substances to waters of the United States in excess of levels set by regulations
and imposes liability in the event of a spill. State laws further provide civil and criminal penalties and liabilities for spills to both
surface and groundwaters and require permits that set limits on discharges to such waters.

Hydraulic Fracturing. Our exploration and production activities may involve the use of hydraulic fracturing techniques
to stimulate wells and maximize natural gas production. Citing concerns over the potential for hydraulic fracturing to impact
drinking water, human health and the environment, and in response to a Congressional directive, the USEPA has commissioned
a study to identify potential risks associated with hydraulic fracturing. In June 2015, the USEPA released for public comment and
peer review, a draft assessment of the potential impacts of hydraulic fracturing on drinking water resources. Additionally, the draft
has generated substantial public comment and the USEPA’s Science Advisory Board has scheduled public meetings and
teleconferences through at least March 2016 to receive comment on the study. The study’s findings are intended to improve
scientific understanding to guide USEPA’s regulatory oversight, guidance and, where appropriate, rulemaking related to hydraulic
fracturing. Some states now regulate utilization of hydraulic fracturing and others are in the process of developing, or are considering
development of, such rules to address the potential for drinking water impacts, induced seismicity, and other concerns. In several
localities and in New York, use of hydraulic fracturing has been banned, although local fracking bans are prohibited in Texas and
Oklahoma. Depending on the results of the USEPA study and other developments related to the impact of hydraulic fracturing,
our drilling activities could be subjected to new or enhanced federal, state and/or local requirements governing hydraulic fracturing.

Air Emissions. Our operations are subject to local, state and federal regulations for the control of emissions from sources
of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits may be resolved
by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could impose civil
and criminal liability for non-compliance. An agency could require us to forego construction or operation of certain air emission
sources. We believe that we are in substantial compliance with air pollution control requirements.

According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly
known as greenhouse gases (“GHG”) may be contributing to global warming of the earth's atmosphere and to global climate
change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions.
The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act (“CAA”) definition of an “air
pollutant”, and in response the USEPA promulgated an endangerment finding paving the way for regulation of GHG emissions
under the CAA. The USEPA has also promulgated rules requiring large sources to report their GHG emissions. Sources subject
to these reporting requirements include on- and offshore petroleum and natural gas production and onshore natural gas processing
and distribution facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year in aggregate emissions from
all site sources. We are not subject to GHG reporting requirements. In addition, the USEPA promulgated rules that significantly
increase the GHG emission threshold that would identify major stationary sources of GHG subject to CAA permitting programs.
As currently written and based on current Company operations, we are not subject to federal GHG permitting requirements.

Regulation of GHG emissions is developing and highly controversial, and further regulatory, legislative and judicial developments
are likely to occur. Such developments may affect how these GHG initiatives will impact the Company. Due to the uncertainties
surrounding the regulation of and other risks associated with GHG emissions, the Company cannot predict the financial impact
of related developments on the Company.

The USEPA has promulgated rules to limit air emissions from many hydraulically fractured natural gas wells. These
regulations require use of equipment to capture gases that come from the well during the drilling process (so-called green
completions). Other new requirements mandate tighter standards for emissions associated with gas production, storage and
transport. In August 2015, USEPA proposed rules to address methane emissions at new oil and gas wells and in January 2016,
BLM proposed new rules to limit flaring on public and tribal lands. While these new requirements are expected to increase the
cost of natural gas production, we do not anticipate that we will be affected any differently than other producers of natural gas.

Coastal Coordination. There are various federal and state programs that regulate the conservation and development of
coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed to preserve and, where possible, restore the
natural resources of the Nation's coastal zone. The CZMA provides for federal grants for state management programs that regulate
land use, water use and coastal development.

The Louisiana Coastal Zone Management Program (“LCZMP”) was established to protect, develop and, where feasible,
restore and enhance coastal resources of the state. Under the LCZMP, coastal use permits are required for certain activities, even
if the activity only partially infringes on the coastal zone. Among other things, projects involving use of state lands and water
bottoms, dredge or fill activities that intersect with more than one body of water, mineral activities, including the exploration and
production of oil and gas, and pipelines for the gathering, transportation or transmission of oil, gas and other minerals require such
permits. General permits, which entail a reduced administrative burden, are available for a number of routine oil and gas
activities. The LCZMP and its requirement to obtain coastal use permits may result in additional permitting requirements and
associated project schedule constraints.

The Texas Coastal Coordination Act (“CCA”) provides for coordination among local and state authorities to protect
coastal resources through regulating land use, water, and coastal development and establishes the Texas Coastal Management
Program that applies in the nineteen counties that border the Gulf of Mexico and its tidal bays. The CCA provides for the review
of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management
Plan. This review may affect agency permitting and may add a further regulatory layer to some of our projects.

OSHA. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable
state statutes. The OSHA hazard communication standard, the USEPA community right-to-know regulations under Title III of the
federal Superfund Amendments and Reauthorization Act, and similar state statutes require us to organize and/or disclose
information about hazardous materials used or produced in our operations. Certain of this information must be provided to
employees, state and local governmental authorities and local citizens.

Management believes that we are in substantial compliance with current applicable environmental laws and regulations

described above and that continued compliance with existing requirements will not have a material adverse impact on us.

Corporate Offices

Our headquarters are located in Lafayette, Louisiana, in approximately 45,800 square feet of leased space, with exploration
offices in The Woodlands, Texas and Tulsa, Oklahoma, in approximately 13,100 square feet and 11,800 square feet, respectively,
of leased space. We also maintain owned or leased field offices in the areas of the major fields in which we operate properties or
have a significant interest. Replacement of any of our leased offices would not result in material expenditures by us as alternative
locations to our leased space are anticipated to be readily available.

Employees

We had 119 full-time employees as of February 8, 2016. In addition to our full time employees, we utilize the services
of independent contractors to perform certain functions. We believe that our relationships with our employees are satisfactory.
None of our employees are covered by a collective bargaining agreement.

Available Information

We make available free of charge, or through the “Investors—SEC Documents” section of our website at
www.petroquest.com, access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K,
and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably
practicable after such material is filed or furnished to the Securities and Exchange Commission. Our Code of Business Conduct
and Ethics, our Corporate Governance Guidelines and the charters of our Audit, Compensation and Nominating and Corporate

Governance Committees are also available through the “Investors—Corporate Governance” section of our website or in print to
any stockholder who requests them.

Item 1A. Risk Factors

Risks Related to Our Business, Industry and Strategy

Oil and natural gas prices are volatile and oil prices have been significantly depressed since the end of 2014. The extended
decline in the prices of oil and natural gas has adversely affected, and will continue to adversely affect our financial condition,
liquidity and results of operations.

Our future financial condition, revenues, results of operations, profitability and future growth, and the carrying value of
our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production. Our ability to
maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon
oil and natural gas prices. Historically, the markets for oil and natural gas have been volatile and oil prices have been significantly
depressed since the end of 2014 as demonstrated by the SEC pricing for the value of crude oil and natural gas, which has decreased
significantly as of December 31, 2015 as compared to December 31, 2014. For example, the SEC pricing at December 31, 2015
for crude oil (WTI Cushing) and natural gas (Henry Hub) was $50.28 per Bbl and $2.58 per MMBtu, respectively, as compared
to $94.99 per Bbl to a low of $4.35 per MMBtu for crude oil and natural gas, respectively, as to December 31, 2014. These markets
will likely continue to be volatile in the future. The prices we will receive for our production, and the levels of our production,
will depend on numerous factors beyond our control.

These factors include:

•

relatively minor changes in the supply of or the demand for oil and natural gas;

the condition of the United States and worldwide economies;

• market uncertainty;

•

the level of consumer product demand;

• weather conditions in the United States, such as hurricanes;

•

the actions of the Organization of Petroleum Exporting Countries;

domestic and foreign governmental regulation and taxes, including price controls adopted by the FERC;

political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South
America;

the price and level of foreign imports of oil and natural gas; and

the price and availability of alternate fuel sources.

We cannot predict future oil and natural gas prices and such prices may decline. Likewise we cannot predict how long
the current downturn in crude oil and natural gas prices will continue. The extended decline in oil and natural gas prices has
adversely affected, and may continue to adversely affect, our financial condition, liquidity and results of operations. Lower prices
have reduced and may further reduce the amount of oil and natural gas that we can produce economically and have required and
may require us to record additional ceiling test write-downs and may cause our estimated proved reserves at December 31, 2016
to decline compared to our estimated proved reserves at December 31, 2015. Substantially all of our oil and natural gas sales are
made in the spot market or pursuant to contracts based on spot market prices. Our sales are not made pursuant to long-term fixed
price contracts.

To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected
future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or
natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material
adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Our outstanding indebtedness may adversely affect our cash flow and our ability to operate our business, which in turn may
limit our ability to remain in compliance with debt covenants and make payments on our debt.

The aggregate principal amount of our outstanding indebtedness, net of cash on hand, as of December 31, 2015 was
$202.0 million. After giving effect to the the Exchange Offering, the aggregate principal amount of our outstanding indebtedness,
net of cash on hand was $185.9 million. We currently have $42 million of availability under our bank credit facility, subject to
compliance with the financial covenants thereunder, which, based on the Company’s expectations for the first quarter of 2016,
will effectively limit the availability to 25% of the aggregate commitment of the lenders, or $10.5 million. In addition, we may
also incur additional indebtedness in the future. Specifically, our high level of debt could have important consequences for you,
including the following:

•

it may be more difficult for us to satisfy our obligations with respect to our outstanding indebtedness, including our
10% senior secured notes and our 10% Senior Notes due 2017 (the “10% senior notes”), and any failure to comply
with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result
in an event of default under the agreements governing such indebtedness;

the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions,
capital expenditures or to meet our operating expenses or other general corporate obligations and may limit our
flexibility in operating our business;

• we will need to use a substantial portion of our cash flows to pay interest on our debt, approximately $28 million
per year for interest on our 10% senior secured notes and 10% senior notes alone, and to pay quarterly dividends
(which we plan to suspend beginning with the dividend payment due in April 2016), if permissible under the terms
of our debt agreements and declared by our Board of Directors, on our 6.875% Series B Cumulative Convertible
Perpetual Preferred Stock (the "Series B Preferred Stock") of approximately $5.1 million per year, which will reduce
the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or
other business activities;

•

the amount of our interest expense may increase because certain of our borrowings in the future may be at variable
rates of interest, which, if interest rates increase, could result in higher interest expense;

• we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;

• we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in

general, especially extended or further declines in oil and natural gas prices; and

•

our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in
which we operate.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by
financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic
conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to
pay the principal and interest on our debt, including our 10% senior secured notes and 10% senior notes, and meet our other
obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt,
including our 10% senior secured notes and 10% senior notes, sell assets, borrow more money or raise equity. We may not be able
to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors
beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of
operations.

Our ability to make payments on and to refinance our indebtedness, including our 10% senior secured notes and 10%
senior notes, and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations
in the future. To a certain extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions
and other factors that are beyond our control, including the prices that we receive for our oil and natural gas production.

We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will
be available to us under our bank credit facility in an amount sufficient to enable us to pay principal and interest on our indebtedness,
including our 10% senior secured notes and 10% senior notes, or to fund our other liquidity needs. If our cash flow and capital
resources are insufficient to fund our debt obligations, we may be forced to reduce our planned capital expenditures, sell assets,

seek additional equity or debt capital or restructure our debt. We cannot assure you that any of these remedies could, if necessary,
be affected on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and
principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to
incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest
on and principal of our debt in the future, including payments on our 10% senior secured notes and 10% senior notes, and any
such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could
cause us to default on our obligations and could impair our liquidity.

A financial downturn or negative credit market conditions may have lasting effects on our liquidity, business and financial
condition that we cannot predict.

Liquidity is essential to our business. Our liquidity could be substantially negatively affected by an inability to obtain
capital in the long-term or short-term debt capital markets or equity capital markets or an inability to access bank financing. A
prolonged credit crisis or turmoil in the domestic or global financial systems could materially affect our liquidity, business and
financial condition. These conditions have adversely impacted financial markets previously and created substantial volatility and
uncertainty, and could do so again, with the related negative impact on global economic activity and the financial markets. Negative
credit market conditions could materially affect our liquidity and may inhibit our lenders from fully funding our bank credit facility
or cause them to make the terms of our bank credit facility costlier and more restrictive. A weak economic environment could also
adversely affect the collectability of our trade receivables or performance by our suppliers and cause our commodity derivative
arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.
Additionally, negative economic conditions could lead to reduced demand for oil, natural gas and NGLs or lower prices for oil,
natural gas and NGLs, which could have a negative impact on our revenues.

We may not be able to obtain adequate financing when the need arises to execute our long-term operating strategy.

Our ability to execute our long-term operating strategy is highly dependent on having access to capital when the need
arises. We historically have addressed our long-term liquidity needs through bank credit facilities, second lien term credit facilities,
issuances of equity and debt securities, sales of assets, joint ventures and cash provided by operating activities. We will examine
the following alternative sources of long-term capital as dictated by current economic conditions:

•

borrowings from banks or other lenders;

the sale of certain assets;

the issuance of debt securities;

the sale of common stock, preferred stock or other equity securities;

joint venture financing; and

production payments.

The availability of these sources of capital when the need arises will depend upon a number of factors, some of which
are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, our
credit ratings, interest rates, market perceptions of us or the oil and gas industry, our market value and our operating performance.
We may be unable to execute our long-term operating strategy if we cannot obtain capital from these sources when the need arises.

The borrowing base under our bank credit facility may be reduced below the amount of borrowings outstanding under such
facility.

Under the terms of our bank credit facility, our borrowing base is subject to redeterminations at least semi-annually (with
additional interim redeterminations presently scheduled to occur) based in part on prevailing oil and gas prices. A negative
adjustment could occur if the estimates of future prices used by the banks in calculating the borrowing base are significantly lower
than those used in the last redetermination. The next redetermination of our borrowing base is scheduled to occur by March 31,
2016. In addition, the portion of our borrowing base made available to us is subject to the terms and covenants of the bank credit
facility including, without limitation, compliance with the ratios and other financial covenants of such facility. Though we do not
currently have any amounts outstanding, if the amount that may in the future be outstanding under our bank credit facility exceeds
a redetermined borrowing base, we could be forced to repay a portion of our borrowings thereunder. We may not have sufficient
funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our
borrowings or arrange new financing, we may have to sell a portion of our assets.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to
changing conditions and engage in other business activities that may be in our best interests.

Our bank credit facility and the indenture governing our 10% senior secured notes contain a number of significant

covenants that, among other things, restrict or limit our ability to:

•

pay dividends or distributions on our capital stock or issue preferred stock;

repurchase, redeem or retire our capital stock or subordinated debt;

• make certain loans and investments;

•

place restrictions on the ability of subsidiaries to make distributions;

sell assets, including the capital stock of subsidiaries;

enter into certain transactions with affiliates;

create or assume certain liens on our assets;

enter into sale and leaseback transactions;

• merge or to enter into other business combination transactions;

•

enter into transactions that would result in a change of control of us; or

engage in other corporate activities.

Also, our bank credit facility and the indenture governing our 10% senior secured notes require us to maintain compliance
with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial
condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial
condition tests. For example, as a result of the impact of the decline in commodity prices, we anticipate that we may exceed the
maximum ratio of total debt to EBITDAX financial covenant included in the bank credit facility as early as the end of the first
quarter of 2016, which would require us to seek a waiver or amendment from the lenders. We cannot provide any assurance that
we will be able to reach an agreement with the lenders on an amendment or waiver on a timely basis or on satisfactory terms to
alleviate any non-compliance with the financial covenants under the bank credit facility.

Further, these financial ratio restrictions and financial condition tests could limit our ability to obtain future financings,
make needed capital expenditures, withstand a future downturn in our business or the economy in general or 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 bank credit facility and the indenture governing our 10% senior secured
notes impose on us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition
tests could result in a default under our bank credit facility and our 10% senior secured notes. A default, if not cured or waived,
could result in all indebtedness outstanding under our bank credit facility and our 10% senior secured notes to become immediately
due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if
new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts,
the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted
debt.

Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate
to protect us against continuing and prolonged declines in commodity prices.

We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices
and to achieve more predictable cash flow. Our hedges at December 31, 2015 and as of the date of this report are in the form of
swaps placed with the commodity trading branches of JPMorgan Chase Bank and The Bank of Nova Scotia, both of which
participate in our bank credit facility. We cannot assure you that these or future counterparties will not become credit risks in the
future. Hedging arrangements expose us to risks in some circumstances, including situations when the counterparty to the hedging
contract defaults on the contractual obligations or there is a change in the expected differential between the underlying price in

the hedging agreement and actual prices received. These hedging arrangements may also limit the benefit we could receive from
increases in the market or spot prices for oil and natural gas.

For the year ended December 31, 2015, our total oil and gas sales included additions related to the settlement of gas
hedges of $15,940,000, oil hedges of $644,000 and Ngl hedges of $530,000, which in total represented 15% of our total oil and
gas sales for the year. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately
protect us from fluctuations in oil and natural gas prices. In addition, at March 1, 2016, we had approximately 2.7 Bcf of gas
volumes hedged for 2016, which represents 10% of our 2016 estimated production, assuming the midpoint of our first quarter
2016 production guidance is held constant for the remainder of the year. These hedges may be inadequate to protect us from
continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current
levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our
results of operations and financial condition would be negatively impacted.

We may be required to post additional collateral to satisfy the collateral requirements related to the surety bonds that secure
our offshore decommissioning obligations.

To cover the costs for various obligations of lessees on the OCS, including costs for such decommissioning obligations
as the plugging of wells, the removal of platforms and other facilities, the decommissioning of pipelines and the clearing of the
seafloor of obstructions typically performed at the end of production, the BOEM generally requires that the lessees post substantial
bonds or other acceptable financial assurances that such obligations will be met. Failure to post the requisite bonds or otherwise
satisfy the BOEM’s security requirements could have a material adverse effect on our ability to operate in the U.S. Gulf of Mexico.

Because we are not exempt from the BOEM’s supplemental bonding requirements, we engage a number of surety
companies to post the requisite bonds. Pursuant to the terms of our agreements with these surety companies, we are required to
post collateral at the outset of the agreement or subsequently on demand, the amount of which typically may be increased at the
surety companies’ discretion. Two of our surety companies recently requested that we post collateral to support certain of the
bonds that are issued on our behalf. We are currently evaluating various options for posting the requested collateral, however,
given the effect of current commodity prices on our creditworthiness and the unwillingness of the surety companies to post bonds
without the requisite collateral, we cannot assure you that we will be able to satisfy current or future demands for collateral for
the requisite bonds or comply with new supplemental bonding requirements. If we fail to do so, we may be in default under our
agreements with the surety companies, which in turn could cause a cross-default under our bank credit facility and potentially the
indenture governing our 10% senior secured notes.

We may be required to provide letters of credit to support the additional collateral or bonding requirements requested by
the BOEM or the surety companies. Such letters of credit would likely be issued under our bank credit facility and would reduce
the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no
assurance that we can continue to obtain bonds or other surety in all cases given these new expenses, and if we are unable to obtain
the additional required bonds or the increased amount of required collateral as requested, the BOEM may require any or all of our
operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties, and any one or more of such
actions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

Our future success depends upon our ability to find, develop, produce and acquire additional oil and natural gas reserves that
are economically recoverable.

As is generally the case in the Gulf Coast Basin where approximately 40% of our current production is located, many of
our producing properties are characterized by a high initial production rate, followed by a steep decline in production. In order to
maintain or increase our reserves, we must constantly locate and develop or acquire new oil and natural gas reserves to replace
those being depleted by production. We must do this even during periods of low oil and natural gas prices when it is difficult to
raise the capital necessary to finance our exploration, development and acquisition activities. Without successful exploration,
development or acquisition activities, our reserves and revenues will decline rapidly. We may not be able to find and develop or
acquire additional reserves at an acceptable cost or have access to necessary financing for these activities, either of which would
have a material adverse effect on our financial condition.

Approximately 40% of our production is exposed to the additional risk of severe weather, including hurricanes and tropical
storms, as well as flooding, coastal erosion and sea level rise.

At December 31, 2015, approximately 40% of our production and approximately 25% of our estimated proved reserves
are located in the Gulf of Mexico and along the Gulf Coast Basin. Operations in this area are subject to severe weather, including
hurricanes and tropical storms, as well as flooding, coastal erosion and sea level rise. Some of these adverse conditions can be
severe enough to cause substantial damage to facilities and possibly interrupt production. For example, certain of our Gulf Coast
Basin properties have experienced damages and production downtime as a result of storms including Hurricanes Katrina and Rita,
and more recently Hurricanes Gustav and Ike. In addition, according to certain scientific studies, emissions of carbon dioxide,
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methane, nitrous oxide and other gases commonly known as greenhouse gases may be contributing to global warming of the earth's
atmosphere and to global climate change, which may exacerbate the severity of these adverse conditions. As a result, such conditions
may pose increased climate-related risks to our assets and operations.

In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks; however,
losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot assure you that we will
be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will
be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and
results of operations.

SEC rules could limit our ability to book additional proved undeveloped reserves or require us to write down our proved
undeveloped reserves.

SEC rules require that, 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. This requirement may limit our potential to book additional
proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved
undeveloped reserves if we do not develop those reserves within the required five-year time frame.

Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of proved
reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our
reserve report. These differences may be material.

Although the estimates of our oil and natural gas reserves and future net cash flows attributable to those reserves were
prepared by Ryder Scott Company, L.P., our independent petroleum and geological engineers, we are ultimately responsible for
the disclosure of those estimates. Reserve engineering is a complex and subjective process of estimating underground accumulations
of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas
reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

•

historical production from the area compared with production from other similar producing wells;

the assumed effects of regulations by governmental agencies;

assumptions concerning future oil and natural gas prices; and

assumptions concerning future operating costs, severance and excise taxes, development costs and work-over and
remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those

assumed in estimating proved reserves:

•

the quantities of oil and natural gas that are ultimately recovered;

the production and operating costs incurred;

the amount and timing of future development expenditures; and

future oil and natural gas sales prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same
available data. Historically, the difference between our actual production and the production estimated in a prior year's reserve
report has not been material. Our 2015 production, excluding the impact from successful exploration wells which are not included
in the prior year reserve report, was approximately 31% lower than amounts projected in our 2014 reserve report as a result of the
Oklahoma Divestiture. We cannot assure you that these differences will not be material in the future.

Approximately 42% of our estimated proved reserves at December 31, 2015 are undeveloped and 20% were developed,
non-producing. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The
reserve data assumes that we will make significant capital expenditures to develop and produce our reserves. Although we have
prepared estimates of our oil and natural gas reserves and the costs associated with these reserves in accordance with industry
standards, we cannot assure you that the estimated costs are accurate, that the development will occur as scheduled or that the
actual results will be as estimated. In addition, the recovery of certain developed non-producing reserves (primarily in the Gulf
of Mexico) is generally subject to the approval of development plans and related activities by applicable state and/or federal
agencies. Statutes and regulations may affect both the timing and quantity of recovery of estimated reserves. Such statutes and

regulations, and their enforcement, have changed in the past and may change in the future, and may result in upward or downward
revisions to current estimated proved reserves.

You should not assume that the standardized measure of discounted cash flows is the current market value of our estimated
oil and natural gas reserves. In accordance with SEC requirements, the standardized measure of discounted cash flows from proved
reserves at December 31, 2015 are based on twelve-month average prices and costs as of the date of the estimate. These prices
and costs will change and may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes
in consumption by oil and natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash
flows. The actual timing of development activities, including related production and expenses, will affect the timing of future net
cash flows and any differences between estimated development timing and actual could have a material effect on standardized
measure. In addition, the 10% discount factor we use when calculating standardized measure of discounted cash flows for reporting
requirements in compliance with accounting requirements is not necessarily the most appropriate discount factor. The effective
interest rate at various times and the risks associated with our operations or the oil and natural gas industry in general will affect
the accuracy of the 10% discount factor.

We may be unable to successfully identify, execute or effectively integrate future acquisitions, which may negatively affect our
results of operations.

Acquisitions of oil and gas businesses and properties have been an important element of our business, and we will continue
to pursue acquisitions in the future. In the last several years, we have pursued and consummated acquisitions that have provided
us opportunities to grow our production and reserves. Although we regularly engage in discussions with, and submit proposals to,
acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate
acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition or, if the
acquisition occurs, effectively integrate the acquired business into our existing business. Negotiations of potential acquisitions
and the integration of acquired business operations may require a disproportionate amount of management's attention and our
resources. Even if we complete additional acquisitions, continued acquisition financing may not be available or available on
reasonable terms, any new businesses may not generate revenues comparable to our existing business, the anticipated cost
efficiencies or synergies may not be realized and these businesses may not be integrated successfully or operated profitably. The
success of any acquisition will depend on a number of factors, including the ability to estimate accurately the recoverable volumes
of reserves, rates of future production and future net revenues attainable from the reserves and to assess possible environmental
liabilities. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our
results of operations.

Even though we perform due diligence reviews (including a review of title and other records) of the major properties we
seek to acquire that we believe is consistent with industry practices, these reviews are inherently incomplete. It is generally not
feasible for us to perform an in-depth review of every individual property and all records involved in each acquisition. However,
even an in-depth review of records and properties may not necessarily reveal existing or potential problems or permit us to become
familiar enough with the properties to assess fully their deficiencies and potential. Even when problems are identified, we may
assume certain environmental and other risks and liabilities in connection with the acquired businesses and properties. The discovery
of any material liabilities associated with our acquisitions could harm our results of operations.

In addition, acquisitions of businesses may require additional debt or equity financing, resulting in additional leverage
or dilution of ownership. Our bank credit facility contains certain covenants that limit, or which may have the effect of limiting,
among other things acquisitions, capital expenditures, the sale of assets and the incurrence of additional indebtedness.

The loss of key management or technical personnel could adversely affect our ability to operate.

Our operations are dependent upon a diverse group of key senior management and technical personnel. In addition, we
employ numerous other skilled technical personnel, including geologists, geophysicists and engineers that are essential to our
operations. We cannot assure you that such individuals will remain with us for the immediate or foreseeable future. The unexpected
loss of the services of one or more of any of these key management or technical personnel could have an adverse effect on our
operations.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on
our financial condition and operations.

We maintain several types of insurance to cover our operations, including worker's compensation, maritime employer's
liability and comprehensive general liability. Amounts over base coverages are provided by primary and excess umbrella liability
policies. We also maintain operator's extra expense coverage, which covers the control of drilling or producing wells as well as
redrilling expenses and pollution coverage for wells out of control.

We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or we could experience
losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant event that is not fully
insured or indemnified occurs, it could materially and adversely affect our financial condition and results of operations.

Lower oil and natural gas prices may cause us to record ceiling test write-downs, which could negatively impact our results of
operations.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize
the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized
costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated
future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or
fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and
natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended.
This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our
net income and stockholders' equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.

We review the net capitalized costs of our properties quarterly, using a single price based on the beginning of the month
average of oil and natural gas prices for the prior 12 months. We also assess investments in unevaluated properties periodically
to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our
oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we
experience substantial downward adjustments to our estimated proved reserves or our unevaluated property values, or if estimated
future development costs increase. As a result of the decline in commodity prices, we recognized ceiling test write-downs totaling
$266.6 million during the year ended December 31, 2015. Utilizing current strip prices for oil and gas prices for the first quarter
of 2016 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of March 31, 2016,
we expect to recognize an additional ceiling test write-down of $20 million to $40 million in the first quarter of 2016.

Factors beyond our control affect our ability to market oil and natural gas.

The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.
The marketability of our production depends upon the availability and capacity of natural gas gathering systems, pipelines and
processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing
wells or the delay or discontinuance of development plans for properties. Our ability to market oil and natural gas also depends
on other factors beyond our control. These factors include:

•

the level of domestic production and imports of oil and natural gas;

the proximity of natural gas production to natural gas pipelines;

the availability of pipeline capacity;

the demand for oil and natural gas by utilities and other end users;

the availability of alternate fuel sources;

the effect of inclement weather, such as hurricanes;

state and federal regulation of oil and natural gas marketing; and

federal regulation of natural gas sold or transported in interstate commerce.

If these factors were to change dramatically, our ability to market oil and natural gas or obtain favorable prices for our

oil and natural gas could be adversely affected.

The explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico in April 2010 and the resulting oil spill
may significantly increase our risks, costs and delays.

The explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico in April 2010 and the resulting
oil spill may significantly impact the risks we face. The Deepwater Horizon incident and resulting legislative, regulatory and
enforcement changes, including increased tort liability, could increase our liability if any incidents occur on our offshore operations.
We cannot predict the ultimate impact the Deepwater Horizon incident and resulting changes in regulation of offshore oil and
natural gas operations will have on our business or operations.

In response to the spill, and during a moratorium on deepwater (below 500 feet) drilling activities implemented between
May 30, 2010 and October 12, 2010, the BOEMRE issued a series of active “Notices to Lessees and Operators”,("NTLs"), and
adopted changes to its regulations to impose a variety of new measures intended to help prevent a similar disaster in the future.

Offshore operators, including those operating in deepwater, OCS waters and shallow waters, where we have substantial
operations, must comply with strict new safety and operating requirements. For example, permit applications for drilling projects
must meet new standards with respect to well design, casing and cementing, blowout preventers, safety certification, emergency
response, and worker training. Operators in all offshore waters are also required to demonstrate the availability of adequate spill
response and blowout containment resources. In addition, the BSEE imposed, for the first time, requirements that offshore operators
maintain comprehensive safety and environmental programs. Such developments have the potential to increase our costs of doing
business.

Federal and state legislation and regulatory initiatives relating to oil and natural gas development and hydraulic fracturing
could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to enhance
oil and natural gas production. Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the
federal Safe Drinking Water Act, but opponents of hydraulic fracturing have called for further study of the technique's environmental
effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if
implemented, would subject all hydraulic fracturing to regulation under the Safe Drinking Water Act. Further, the USEPA is
conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water, and the
draft results were released for public and peer review in June 2015. In addition, in February 2014, the USEPA issued final guidance
for underground injection permits that regulate hydraulic fracturing using diesel fuel, where the USEPA has permitting authority
under the Safe Drinking Water Act. This guidance eventually could encourage other regulatory authorities to adopt permitting and
other restrictions on the use of hydraulic fracturing. In May 2014, the USEPA issued an advance notice of proposed rulemaking
under the Toxic Substances Control Act to obtain data on chemical substances and mixtures used in hydraulic fracturing and
expects to publish a Notice of Proposed Rulemaking on the subject in December 2016. In April 2015, the USEPA proposed
regulations under the federal Clean Water Act to impose pretreatment standards on wastewater discharges associated with hydraulic
fracturing activities and projects issuance of final rules on the subject in August 2016. The USEPA has also promulgated rules to
limit air emissions from many hydraulically fractured natural gas wells. The new regulations will require use of equipment to
capture gases that come from the well during the drilling process (so-called green completions). Other new requirements mandate
tighter standards for emissions associated with gas production, storage and transport. In addition, the BLM finalized rules in
March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian
lands including, for example, notice to and pre-approval by the BLM of the proposed hydraulic fracturing activities; development
and pre-approval by the BLM of a plan for managing and containing flowback fluids and produced water recovered during the
hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities;
and public disclosure of the chemicals used in the hydraulic fracturing fluid (with the exception of certain proprietary information).
The U.S. District Court of Wyoming temporarily stayed implementation of this rule, but the BLM has appealed to the Tenth Circuit
to overturn the stay.

A number of states, including Louisiana, Oklahoma and Texas, have required operators or service companies to disclose
chemical components in fluids used for hydraulic fracturing. Some states have also imposed, or are considering, more stringent
regulation of oil and natural gas exploration and production activities involving hydraulic fracturing by, among other things,
promulgating well completion requirements, imposing controls on storage, recycling and disposal of flowback fluids, and increasing
reporting obligations. In addition, concerns related to the impacts from hydraulic fracturing have led several states and localities
to ban new natural gas development or to impose moratoria on use of hydraulic fracturing in various sensitive areas including
some areas overlying the Marcellus Shale. Similar action could be taken to preclude or limit natural gas development in other
locations.

Recent seismic events have been observed in some areas (including Oklahoma, Ohio and Texas) where hydraulic fracturing
has taken place. Some scientists believe the increased seismic activity may result from deep well fluid injection associated with
use of hydraulic fracturing. Additional regulatory measures designed to minimize or avoid damage to geologic formations have
been imposed in states, including Oklahoma, Ohio and Texas, to address such concerns.

Concerns regarding climate change have led the Congress, various states and environmental agencies to consider a number
of initiatives to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane. Among other things, in
the absence of new federal legislation, the USEPA promulgated regulations imposing reporting and other requirements on sources
of significant emissions of greenhouse gases. Stricter regulations of greenhouse gases could require us to incur costs to reduce
emissions of greenhouse gases associated with our operations, or could adversely affect demand for the oil and natural gas we
produce. In addition, climate change that results in physical effects such as increased frequency and severity of storms, floods

and other climatic events, could disrupt our exploration and production operations and cause us to incur significant costs in
preparing for and responding to those effects.

Although it is not possible at this time to predict the final outcome of the USEPA's study or the requirements of any
additional federal, state or local legislation or regulation regarding hydraulic fracturing, management of drilling fluids, well integrity
requirements or climate change, any new federal or state restrictions imposed on oil and gas exploration and production activities
in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay
our ability to develop oil and natural gas reserves. In addition to increased regulation of our business, we may also experience an
increase in litigation seeking damages as a result of heightened public concerns related to air quality, water quality, and other
environmental impacts.

The adoption of derivatives legislation by Congress, and implementation of that legislation by federal agencies, could have an
adverse impact on our ability to mitigate risks associated with our business.

On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the
“Dodd-Frank Reform Act”), which, among other provisions, establishes federal oversight and regulation of the over-the-counter
derivatives market and entities that participate in that market. The legislation required the Commodities Futures Trading
Commission, (the “CFTC”), and the SEC to promulgate rules and regulations implementing the new legislation, which they have
done since late 2010. The CFTC has introduced dozens of proposed rules coming out of the Dodd-Frank Reform Act, and has
promulgated numerous final rules based on those proposals. The effect of the proposed rules and any additional regulations on
our business is not yet entirely clear, but it is increasingly clear that the costs of derivatives-based hedging for commodities will
likely increase for all market participants. Of particular concern, the Dodd-Frank Reform Act does not explicitly exempt end users
from the requirements to post margin in connection with hedging activities. While several senators have indicated that it was not
the intent of the Dodd-Frank Reform Act to require margin from end users, the exemption is not in the Dodd- Frank Reform Act.
While rules proposed by the CFTC and federal banking regulators appear to allow for non-cash collateral and certain exemptions
from margin for end users, the rules are not final and uncertainty remains. The full range of new Dodd-Frank Reform Act
requirements to be enacted, to the extent applicable to us or our derivatives counterparties, may result in increased costs and cash
collateral requirements for the types of derivative instruments we use to mitigate and otherwise manage our financial and commercial
risks related to fluctuations in oil and natural gas prices. In addition, final rules were promulgated by the CFTC imposing federally-
mandated position limits covering a wide range of derivatives positions, including non-exchange traded bilateral swaps related to
commodities including oil and natural gas. These position limit rules were vacated by a Federal court in September 2012. However,
in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps
contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these
new position limit rules are not yet final, their impact on us is uncertain at this time. If these position limits rules go into effect in
the future, they are likely to increase regulatory monitoring and compliance costs for all market participants, even where a given
trading entity is not in danger of breaching position limits. These and other regulatory developments stemming from the Dodd-
Frank Reform Act, including stringent new reporting requirements for derivatives positions and detailed criteria that must be
satisfied to continue to enter into uncleared swap transactions, could have a material impact on our derivatives trading and hedging
activities in the form of increased transaction costs and compliance responsibilities. Any of the foregoing consequences could
have a material adverse effect on our financial position, results of operations and cash flows.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of
operations and cash flows.

From time to time legislative proposals are made that would, if enacted, make significant changes to U.S. tax laws. These
proposed changes have included, among others, eliminating the immediate deduction for intangible drilling and development
costs, eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and
development, repealing the percentage depletion allowance for oil and natural gas properties and extending the amortization period
for certain geological and geophysical expenditures. Such proposed changes in the U.S. tax laws, if adopted, or other similar
changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development,
could adversely affect our business, financial condition, results of operations and cash flows.

We face strong competition from larger oil and natural gas companies that may negatively affect our ability to carry on
operations.

We operate in the highly competitive areas of oil and natural gas exploration, development and production. Factors that

affect our ability to compete successfully in the marketplace include:

•

the availability of funds and information relating to a property;

the standards established by us for the minimum projected return on investment; and

•

the transportation of natural gas.

Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major
interstate and intrastate pipelines and national and local natural gas gatherers, many of which possess greater financial and other
resources than we do. If we are unable to successfully compete against our competitors, our business, prospects, financial condition
and results of operations may be adversely affected.

Operating hazards may adversely affect our ability to conduct business.

Our operations are subject to risks inherent in the oil and natural gas industry, such as:

•

unexpected drilling conditions including blowouts, cratering and explosions;

uncontrollable flows of oil, natural gas or well fluids;

equipment failures, fires or accidents;

pollution and other environmental risks; and

shortages in experienced labor or shortages or delays in the delivery of equipment.

These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and
equipment, pollution and other environmental damage and suspension of operations. Our offshore operations are also subject to
a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions and more
extensive governmental regulation. These regulations may, in certain circumstances, impose strict liability for pollution damage
or result in the interruption or termination of operations.

Environmental compliance costs and environmental liabilities could have a material adverse effect on our financial condition
and operations.

Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials

into the environment or otherwise relating to environmental protection. These laws and regulations may:

•

require the acquisition of permits before drilling commences;

restrict the types, quantities and concentration of various substances that can be released into the environment from
drilling and production activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and

impose substantial liabilities for pollution resulting from our operations.

The trend toward stricter requirements and standards in environmental legislation and regulation is likely to continue.
Our drilling plans may be delayed, modified or precluded as a result of new or modified environmental mandates, including those
imposed to protect the American Burying Beetle and other endangered species that may be present in the vicinity of our operations.
The enactment of stricter legislation or the adoption of stricter regulations could have a significant impact on our operating costs,
as well as on the oil and natural gas industry in general.

Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials,
remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by
previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could
have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our
operations, including limited coverage for sudden and accidental environmental damages, but this insurance may not extend to
the full potential liability that could be caused by sudden and accidental environmental damages nor continue to be available in
the future, and if available, may not cover environmental damages that occur over time. Accordingly, we may be subject to liability
or may lose the ability to continue exploration or production activities upon substantial portions of our properties if certain
environmental damages occur.

We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability
of these non-operated properties.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise
influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and
development activities on our partially owned properties operated by others therefore will depend upon a number of factors outside
of our control, including the operator's:

•

timing and amount of capital expenditures;

expertise and diligence in adequately performing operations and complying with applicable agreements;

financial resources;

inclusion of other participants in drilling wells; and

use of technology.

As a result of any of the above or an operator's failure to act in ways that are in our best interest, our allocated production

revenues and results of operations could be adversely affected.

Ownership of working interests and overriding royalty interests in certain of our properties by certain of our officers and
directors potentially creates conflicts of interest.

Certain of our executive officers and directors or their respective affiliates are working interest owners or overriding
royalty interest owners in certain properties. In their capacity as working interest owners, they are required to pay their proportionate
share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding
royalty interest owners they are entitled to receive their proportionate share of revenues in the normal course of business. There
is a potential conflict of interest between us and such officers and directors with respect to the drilling of additional wells or other
development operations with respect to these properties.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations
information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create
erroneous information in our hardware or software network infrastructure, possible consequences include our loss of
communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process
commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have
a material adverse effect on our business.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may
adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations.
If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and
natural gas, potentially putting downward pressure on demand for our production and causing a reduction in our revenues. Oil
and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if
infrastructure integral to our customers' operations is destroyed or damaged. Costs for insurance and other security may increase
as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Relating to Our Outstanding Common Stock

Our stock price could be volatile, which could cause you to lose part or all of your investment.

The stock market has from time to time experienced significant price and volume fluctuations that may be unrelated to
the operating performance of particular companies. In particular, the market price of our common stock, like that of the securities
of many other energy companies, has been and may continue to be highly volatile. During 2015, the sales price of our stock ranged
from a low of $0.31 per share (on December 22, 2015) to a high of $3.83 per share (on January 2, 2015). Factors such as
announcements concerning changes in prices of oil and natural gas, the success of our acquisition, exploration and development
activities, the availability of capital, and economic and other external factors, as well as period-to-period fluctuations and financial
results, may have a significant effect on the market price of our common stock.

From time to time, there has been limited trading volume in our common stock. In addition, there can be no assurance
that there will continue to be a trading market or that any securities research analysts will continue to provide research coverage
with respect to our common stock. It is possible that such factors will adversely affect the market for our common stock.

If we cannot meet the New York Stock Exchange’s continuing listing requirements and rules, the New York Stock Exchange
may delist our securities, which could negatively affect our company, the price of our securities and your ability to sell our
securities.

On December 8, 2015, we received a notice from NYSE Regulation, Inc. informing us that we were not in compliance
with the continued listing standards set forth in 802.01C of the Listed Company Manual of the New York Stock Exchange (the
“Listed Company Manual”), because the average closing price of the our common stock fell below $1.00 per share for a period
of over 30 consecutive trading days. We can avoid delisting under this requirement if, during the six month period following receipt
of the notice from the New York Stock Exchange, on the last trading-day of any calendar month, our common stock has a closing
share price of at least $1.00 and an average closing share price of at least $1.00 over the 30 trading-day period ending on the last
trading-day of that month. Under the New York Stock Exchange rules, our common stock will continue to be listed on the New
York Stock Exchange during this six month period, subject to our compliance with other listing requirements.

On December 28, 2015, we received another notice from NYSE Regulation, Inc. informing us that we were not in
compliance with the continued listing standards set forth in Section 802.01B of the Listed Company Manual because our average
global market capitalization fell below $50 million over a trailing consecutive 30 trading-day period and our last reported
stockholders’ equity was less than $50 million. We have submitted a business plan to the New York Stock Exchange demonstrating
how, within the next eighteen months, we intend to regain compliance with the continued listing standards set forth in Section
802.01B of the Listed Company Manual. We intend to continue to work with the New York Stock Exchange to attempt to comply
with all continued listing standards. Assuming that the New York Stock Exchange accepts the plan, we will be subject to quarterly
monitoring for compliance with the business plan and our common stock will continue to trade on the New York Stock Exchange
during the eighteen month period, subject to our compliance with other New York Stock Exchange continued listing requirements.
The New York Stock Exchange may choose to shorten the usual compliance period if prior to the end of the eighteen month period
our global market capitalization exceeds $50 million for two consecutive quarters.

If our common stock ultimately were to be delisted for any reason, trading of our securities would thereafter be conducted
in the over-the-counter market or on the National Association of Securities Dealers Inc.’s “electronic bulletin board.” As a
consequence, our stockholders would likely find it more difficult to dispose of, or to obtain accurate quotations as to the prices of
our securities. Such a delisting could negatively impact us by (i) reducing the liquidity and market price of our common stock;
(ii) reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to
raise equity financing; (iii) limiting our ability to use a registration statement to offer and sell freely tradable securities, thereby
preventing us from accessing the public capital markets; and (iv) impairing our ability to provide equity incentives to its employees.

The terms of our debt agreements currently restrict and Delaware law may restrict us from making cash payments with respect
to our Series B Preferred Stock.

Quarterly dividends and cash payments upon conversion or repurchase of our Series B preferred stock will be paid only
if payment of such amounts is not prohibited by our debt agreements, such as our bank credit facility, and assets are legally available
to pay such amounts. Quarterly dividends will only be paid if such dividends are declared by our board of directors. The board of
directors is not obligated or required to declare quarterly dividends even if we have funds available for such purposes.

The terms of our bank credit facility currently restrict us from paying cash dividends on our Series B preferred stock and
we plan to suspend the dividend beginning with the dividend payment due on April 15, 2016. Under the terms of the Series B
preferred stock, any unpaid dividends will accumulate. If we fail to pay six quarterly dividends on the Series B preferred stock,
whether or not consecutive, holders of the Series B preferred stock, voting as a single class, will have the right to elect two additional
directors to our board of directors until all accumulated and unpaid dividends on the Series B preferred stock are paid in full. We
plan to periodically re-evaluate the dividend payment policy, subject to the terms of our bank credit facility.

If in the future we are permitted to pay such cash dividends under the terms of our existing debt agreements, including
our bank credit facility, and any debt agreements that we enter into in the future, we may continue to be limited in our ability to
pay cash dividends on our Series B preferred stock and our ability to make any cash payment upon conversion or repurchase of
our Series B preferred stock by the terms of such debt agreements. Furthermore, if we are in default under our bank credit facility,
the indenture governing our 10% senior notes, or the indenture governing the 10% senior secured notes, we will not be permitted
to pay any cash dividends on our Series B preferred stock or make any cash payment upon conversion or repurchase of our Series
B preferred stock in the absence of a waiver of such default or an amendment or refinancing of such debt agreements.

Delaware law provides that we may pay dividends on our Series B preferred stock only to the extent that assets are legally
available to pay such dividends. Cash payments we may make upon repurchase or conversion of our Series B preferred stock
would be generally subject to the same restrictions under Delaware law. Legally available assets is defined as the amount of surplus.
Our surplus is the amount by which the fair value of total assets exceeds the sum of:

•

the fair value of our total liabilities, including our contingent liabilities; and

the amount of our capital.

If there is no surplus, legally available assets will mean, in the case of a dividend, our net profits for the fiscal year in

which the dividend payment occurs and/or the preceding fiscal year.

Issuance of shares in connection with financing transactions or under stock incentive plans will dilute current stockholders.

We have issued 1,495,000 shares of Series B Preferred Stock, which are presently convertible into 5,147,734 shares of
our common stock. In addition, pursuant to our stock incentive plan, our management is authorized to grant stock awards to our
employees, directors and consultants. You will incur dilution upon the conversion of the Series B Preferred Stock, the exercise of
any outstanding stock awards or the grant of any restricted stock. In addition, if we raise additional funds by issuing additional
common stock, or securities convertible into or exchangeable or exercisable for common stock, further dilution to our existing
stockholders will result, and new investors could have rights superior to existing stockholders.

The number of shares of our common stock eligible for future sale could adversely affect the market price of our stock.

At December 31, 2015, we had reserved approximately 1.4 million shares of common stock for issuance under outstanding
options and approximately 5.1 million shares issuable upon conversion of the Series B Preferred Stock. All of these shares of
common stock are registered for sale or resale on currently effective registration statements. In addition, we recently issued
approximately 4.3 million shares in connection with the private Exchange Offering that will be eligible for future sale under Rule
144 of the Securities Act. We may issue additional restricted securities or register additional shares of common stock under the
Securities Act in the future. The issuance of a significant number of shares of common stock upon the exercise of stock options,
the granting of restricted stock or the conversion of the Series B Preferred Stock, or the availability for sale, or sale, of a substantial
number of the shares of our common stock eligible for future sale under effective registration statements, under Rule 144 or
otherwise, could adversely affect the market price of the common stock.

Provisions in our certificate of incorporation and bylaws could delay or prevent a change in control of our company, even if
that change would be beneficial to our stockholders.

Certain provisions of our certificate of incorporation and bylaws may delay, discourage, prevent or render more difficult
an attempt to obtain control of our company, whether through a tender offer, business combination, proxy contest or otherwise.
These provisions include:

•

the charter authorization of “blank check” preferred stock;

a restriction on the ability of stockholders to call a special meeting and take actions by written consent; and

provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action
at annual meetings of our stockholders.

We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.

We have not paid dividends on our common stock, in cash or otherwise, and intend to retain our cash flow from operations
for the future operation and development of our business. We are currently restricted from paying dividends on our common stock
by our bank credit facility, the indenture governing the 10% senior secured notes and, in some circumstances, by the terms of our
Series B Preferred Stock. Any future dividends also may be restricted by our then-existing debt agreements.

Item 1B Unresolved Staff Comments

None

Item 3.

Legal Proceedings

PetroQuest is involved in litigation relating to claims arising out of its operations in the normal course of business,
including worker’s compensation claims, tort claims and contractual disputes. Some of the existing known claims against us are
covered by insurance subject to the limits of such policies and the payment of deductible amounts by us. Management believes

that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material
adverse effect on PetroQuest’s business or financial position.

Item 4.

Mine Safety Disclosures

Not applicable.

PART II

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

The following graph illustrates the yearly percentage change in the cumulative stockholder return on our common stock,
compared with the cumulative total return on the NYSE/AMEX Stock Market (U.S. Companies) Index, the NYSE Stocks—Crude
Petroleum and Natural Gas Index and the Morningstar Oil and Gas E&P Index, for the five years ended December 31, 2015.

Comparison of 5 Year Cumulative Total Return
Assumes Initial Investment of $100
December 31, 2015

PetroQuest Energy,
Inc.

NYSE/AMEX/
NASDAQ Market
(US Companies)

NYSE Stocks (SIC
1310-1319 US
Companies) Crude
Petroleum and
Natural Gas

Morningstar Oil &
Gas E&P Index

12/31/2010

12/31/2011

12/31/2012

12/31/2013

12/31/2014

12/31/2015

$100.00

87.65

65.74

57.37

49.67

6.64

$100.00

90.62

92.98

93.07

76.10

52.25

$100.00

91.44

89.44

107.19

86.70

57.23

$100.00

101.04

116.84

153.61

170.23

163.89

Market Price of and Dividends on Common Stock

Our common stock trades on the New York Stock Exchange under the symbol “PQ.” The following table lists high and

low sales prices per share for the periods indicated:

2014

1st Quarter
2nd Quarter
3rd Quarter
4th Quarter

2015

1st Quarter
2nd Quarter
3rd Quarter
4th Quarter

High
5.93 $
7.82
7.76
5.66

3.83 $
2.74
1.99
1.51

Low
3.66
5.17
5.13
3.15

1.95
1.70
1.05
0.31

As of February 26, 2016, there were 252 common stockholders of record.

We have never paid a dividend on our common stock, cash or otherwise, and intend to retain our cash flow from operations
for the future operation and development of our business. In addition, under our bank credit facility, the indenture governing the
10% senior secured notes, and, in some circumstances, the terms of our Series B Preferred Stock, we are restricted from paying
cash dividends on our common stock. The payment of future dividends, if any, will be determined by our Board of Directors in
light of conditions then existing, including our earnings, financial condition, capital requirements, restrictions in financing
agreements, business conditions and other factors. See Item 1A. “Risk Factors – Risks Relating to our Outstanding Common Stock
– We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.”

The following table sets forth certain information with respect to repurchases of our common stock during the quarter

ended December 31, 2015.

Total Number of
Shares
Purchased (1)

Average Price
Paid Per Share

5,049 $

252,157 $

— $

1.35

1.08

—

Total Number of
Shares Purchased
as Part of
Publicly
Announced Plan
or Program

Maximum Number (or
Approximate Dollar
Value) of Shares that May
be Purchased Under the
Plans or Programs

—

October 1—October 31, 2015

November 1—November 30, 2015

December 1—December 31, 2015

(1) All shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards.

Item 6.

Selected Financial Data

The following table sets forth, as of the dates and for the periods indicated, selected financial information for the Company.
The financial information for each of the five years in the period ended December 31, 2015 has been derived from the audited
Consolidated Financial Statements of the Company for such periods. The information should be read in conjunction with
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial
Statements and notes thereto. The following information is not necessarily indicative of future results of the Company. All amounts
are stated in U.S. dollars unless otherwise indicated.

2015 (1)

2014

2013

2012 (2)

2011 (3)

Year Ended December 31,

Average sales price per Mcfe
Revenues
Net income (loss) available to common stockholders

3.39
115,969
(299,929)

Net income (loss) available to common stockholders
per share:

(in thousands except per share and per Mcfe data)
$

5.19
225,021
26,051

4.80
182,804
8,943

4.17
141,433
(137,218)

5.32
160,486
5,409

Basic
Diluted

Oil and gas properties, net
Total assets
Long-term debt
Stockholders’ equity

(4.61)
(4.61)
165,952
379,319
347,008
(163,067)

0.39
0.39
683,812
786,108
420,213
136,909

0.14
0.14
581,242
660,018
417,828
99,095

(2.20)
(2.20)
333,946
430,647
147,244
87,591

0.08
0.08
405,351
512,819
146,653
222,390

(1) The year ended December 31, 2015 includes a pre-tax ceiling test write-down of $266.6 million.
(2) The year ended December 31, 2012 includes a pre-tax ceiling test write-down of $137.1 million.
(3) The year ended December 31, 2011 includes a pre-tax ceiling test write-down of $18.9 million.

Item 7.

Overview

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Balance Sheet Restructuring

In response to the decline in commodity prices that began in late 2014, and has continued throughout 2015 and into 2016,

we have initiated the following steps designed to enhance liquidity and reduce indebtedness:

•

Sold the majority of our interests in the Woodford and Mississippian Lime (the “Oklahoma Divestiture”) in June
2015 for $280 million;

• Repaid all borrowings outstanding under our bank credit facility with a portion of the net proceeds from the Oklahoma

Divestiture;

• Reduced capital expenditures during 2015 by 67%, as compared to 2014;

• Approved a 2016 capital expenditure budget down 65% from 2015 spending;

• Completed an Exchange Offering (as described below) in February 2016 that reduced indebtedness by $69.7 million

and extended the maturity on $144.7 million of indebtedness from September 2017 to February 2021; and

• Announced plans to suspend the dividend on our Series B Preferred Stock beginning with the April 2016 payment,

which will save $5.1 million annually.

As a result of the actions outlined above, we have reduced our total indebtedness from $420.2 million at December 31,
2014 to $280.3 million as of the date of this report. Most recently, we completed a private exchange offering whereby participating
bondholders exchanged approximately $214.4 million of 10% Senior Notes due 2017 for approximately $53.6 million in cash,
approximately $144.7 million of our newly issued 10% Senior Secured Second Lien Notes due 2021 and approximately 4.3 million
shares of our common stock (the “Exchange Offering”). As a result of the Exchange Offering, we reduced our annual fixed charges
by $7 million and eliminated or extended the maturity date on 61% of our $350 million of indebtedness as of December 31, 2015.
After completion of the Exchange Offering, we have $280.3 million of total indebtedness with $135.6 million maturing in September
2017 and $144.7 million maturing in February 2021.

In response to the impact that the decline in commodity prices has had on our cash flow, our 2016 capital expenditures,
which include capitalized interest and overhead but exclude acquisitions, are expected to range between $20 million and $25
million and are expected to be funded through cash flow from operations and cash on hand. Because we operate approximately
75% of our total estimated proved reserves and manage the drilling and completion activities on an additional 13% of such reserves,
we expect to be able to control the timing of a substantial portion of our capital investments. We also plan to maintain our commodity
hedging program and, as in prior years, we may continue to opportunistically dispose of certain assets or enter into joint venture
arrangements to provide additional liquidity. In addition, we plan to suspend the quarterly dividend on our outstanding Series B
Preferred Stock beginning with the dividend payment in April 2016 (which will save $5.1 million annually), reduce our cash costs
by 25% from 2015 levels and consider additional options to refinance our remaining $135.6 million of 10% Senior Notes due
2017.

Oklahoma Divestiture:

On June 4, 2015, we completed the sale of a majority of our interests in the Woodford and Mississippian Lime (the “Sold
Assets”) for $280 million, subject to customary post-closing purchase price adjustments, effective January 1, 2015. At closing,
we received $257.7 million in cash and recognized a receivable of $13.9 million, which was received in full during the third quarter
of 2015.

In connection with the sale, we entered into a Contract Operating Services Agreement whereby we will retain a minimal
working interest in the Sold Assets and will provide certain services as a contract operator for a period of one year from the closing
date of the sale, subject to renewal for two additional one-year terms.

At December 31, 2014, the estimated proved reserves attributable to the Sold Assets totaled approximately 227.2 Bcfe.
Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with
no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves.
A significant alteration is generally not expected to occur for sales involving less than 25% of the total proved reserves. If the
divestiture of the Sold Assets was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment
would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, we recognized a
gain on the sale of $23.2 million during 2015. The carrying value of the properties sold was determined by allocating total
capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

Fleetwood Joint Venture

In June 2014, we entered into a joint venture in Louisiana for an aggregate purchase price of $24 million. The assets
acquired under the joint venture include an average 37% working interest in an approximately 30,000 acre leasehold position in
Louisiana and exclusive rights, along with our joint venture partner, to a 200 square mile proprietary 3D survey which has generated
several conventional and shallow non-conventional oil focused prospects.

The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion
and lease acquisition costs. At December 31, 2015, $4.4 million of drilling carry remained outstanding which was paid to our joint
venture partner in connection with the terms of the agreement during February 2016.

Gulf of Mexico Acquisition

On July 3, 2013, we closed the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8 million,
reflecting an effective date of January 1, 2013. The Gulf of Mexico Acquisition was financed with the issuance of an additional
$200 million in aggregate principal amount of our 10% Senior Notes due 2017. The acquired assets included 16 gross wells
located on seven platforms.

The Gulf of Mexico Acquisition added 30.5 Bcfe of estimated proved reserves as of December 31, 2013 and increased
our net acreage position in the Gulf Coast Basin by 23%. See "Note 2 - Acquisition & Divestitures" in Item 8. Financial Statements
and Supplementary Data for additional details related to this transaction.

Critical Accounting Policies

Reserve Estimates

Our estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at
which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of
whether deterministic or probabilistic methods are used for the estimation. At the end of each year, our proved reserves are estimated
by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent
projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and
quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically
recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions,
such as historical production from the area compared with production from other producing areas, the assumed effect of regulations
by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes,
development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations
may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in
the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of
our oil and gas properties and/or the rate of depletion of such oil and gas properties.

Disclosure requirements under Staff Accounting Bulletin 113 (“SAB 113”) include provisions that permit the use of new
technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions
about reserve volumes. The rules also allow companies the option to disclose probable and possible reserves in addition to the
existing requirement to disclose proved reserves. The disclosure requirements also require companies to report the independence
and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates.
Pricing is based on a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending
date of the balance sheet to report oil and natural gas reserves. In addition, the 12-month average is also used to measure ceiling
test impairments and to compute depreciation, depletion and amortization.

Full Cost Method of Accounting

We use the full cost method of accounting for our investments in oil and gas properties. Under this method, all acquisition,
exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and
developing oil and natural gas are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire
property. Exploration costs include the costs of drilling exploratory wells, including those in progress and geological and
geophysical service costs in exploration activities. Development costs include the costs of drilling development wells and costs
of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed
in the period incurred. Sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments

of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between
capitalized costs and proved reserves of oil and gas.

The costs associated with unevaluated properties are not initially included in the amortization base and primarily relate
to ongoing exploration activities, unevaluated leasehold acreage and delay rentals, seismic data and capitalized interest. These
costs are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible
impairment or reduction in value.

We compute the provision for depletion of oil and gas properties using the unit-of-production method based upon
production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the
amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated
properties, the amortization base includes estimated future development costs related to non-producing reserves. Our depletion
expense is affected by the estimates of future development costs, unevaluated costs and proved reserves, and changes in these
estimates could have an impact on our future earnings.

We capitalize certain internal costs that are directly identified with acquisition, exploration and development activities.
The capitalized internal costs include salaries, employee benefits, costs of consulting services and other related expenses and do
not include costs related to production, general corporate overhead or similar activities. We also capitalize a portion of the interest
costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated properties and our effective
borrowing rate.

Capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization ("DD&A") and
related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effect of
cash flow hedges in place, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for
related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-
down of oil and gas properties in the quarter in which the excess occurs.

Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from estimated
proved oil and gas reserves will change in the near term. If oil or gas prices remain at current levels or decline further, even for
only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that further write-
downs of oil and gas properties could occur in the future.

Future Abandonment Costs

Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering
systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our
properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market
demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because
these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make
estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the
timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.

Derivative Instruments

We seek to reduce our exposure to commodity price volatility by hedging a portion of our production through commodity
derivative instruments. The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance
sheet. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other
comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because
the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the
fair value of the derivative are recorded in the income statement as derivative income (expense).

Our hedges are specifically referenced to NYMEX prices for oil and natural gas and OPIS Mt. Bellevue pricing for natural
gas liquids. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the
contracts, by analyzing the correlation between NYMEX and OPIS Mt. Bellevue prices and the posted prices we receive from our
designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for
the designated production and the NYMEX and OPIS Mt. Bellevue prices at which the hedges will be settled. At December 31,
2015, our derivative instruments were designated effective cash flow hedges.

Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future
NYMEX and OPIS Mt. Bellevue prices, discount rates and price movements. As a result, we calculate the fair value of our
commodity derivatives using an independent third-party’s valuation model that utilizes market-corroborated inputs that are

observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties’
default risk for derivative assets and an estimate of our default risk for derivative liabilities.

Results of Operations

The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These

historical results are not necessarily indicative of results to be expected in future periods.

Production:

Oil (Bbls)
Gas (Mcf)
Ngl (Mcfe)
Total Production (Mcfe)

Sales:

Total oil sales
Total gas sales
Total ngl sales
Total oil and gas sales

Average sales prices:
Oil (per Bbl)
Gas (per Mcf)
Ngl (per Mcfe)
Per Mcfe

Year Ended December 31,

2015

2014

2013

528,529
25,501,851
5,487,239
34,160,264

26,532,240
75,070,130
14,367,024
115,969,394

50.20
2.94
2.62
3.39

802,509
31,027,671
7,482,310
43,325,035

78,176,377
114,613,267
32,231,090
225,020,734

97.41
3.69
4.31
5.19

680,980
29,225,843
4,754,223
38,065,946

70,476,065
87,449,370
24,878,243
182,803,678

103.49
2.99
5.23
4.80

The above sales and average sales prices include increases (reductions) to revenue related to the settlement of gas hedges of
$15,940,000, ($4,237,000) and $1,098,000, oil hedges of $644,000, $897,000 and ($232,000), and Ngl hedges of $530,000,
$296,000 and $61,000 for the twelve months ended December 31, 2015, 2014 and 2013, respectively.

Comparison of Results of Operations for the Years Ended December 31, 2015 and 2014

Net income (loss) available to common stockholders totaled ($299,929,000) and $26,051,000 for the years ended December 31,
2015 and 2014, respectively. The primary fluctuations were as follows:

Production Total production decreased 21% during the year ended December 31, 2015 as compared to the 2014 period. The
decrease in total production was due primarily to the Oklahoma Divestiture and normal production declines at our Gulf Coast
fields. Partially offsetting these decreases were increases relating to the successful drilling program in our Carthage field as well
as our Thunder Bayou discovery. As a result of the current low commodity price environment, our 2016 capital expenditures
budget will be significantly lower as compared to 2015. We expect our total production in 2016 to generally approximate 2015
as a result of several recompletions in the Gulf Coat Basin and our limited drilling program in East Texas.

Gas production during the year ended December 31, 2015 decreased 18% from the 2014 period. The decrease in gas production
was due to the Oklahoma Divestiture and normal production declines at our Gulf Coast field, partially offset by the successful
drilling program in our Carthage field and the completion of our Thunder Bayou discovery. As a result of a scheduled recompletion
of our Thunder Bayou discovery and our limited drilling program in East Texas, we expect our 2016 average daily gas production
to generally approximate 2015.

Oil production during the year ended December 31, 2015 decreased 34% as compared to the 2014 period due primarily to normal
production declines at our Gulf Coast fields, downtime at certain of our Gulf of Mexico properties and the divestiture of our Fort
Trinidad field in July 2015 and our Eagleford field in September, 2014. As a result of normal production declines at certain of
our legacy Gulf Coast fields, we expect our average daily oil production to decrease during 2016 as compared to 2015.

Ngl production during the year ended December 31, 2015 decreased 27% from the 2014 period due to the Oklahoma Divestiture
and normal production declines at our Gulf Coast fields, partially offset by the successful drilling program in our Carthage field
and the completion of our Thunder Bayou discovery. As a result of the decrease in drilling activity planned during 2016 and the
divestiture of our liquids rich Oklahoma wells, we expect our daily Ngl production for 2016 to decrease compared to that of 2015.

Prices Including the effects of our hedges, average gas prices per Mcf for the year ended December 31, 2015 were $2.94 as
compared to $3.69 for the 2014 period. Average oil prices per Bbl for the year ended December 31, 2015 were $50.20 as compared
to $97.41 for the 2014 period and average Ngl prices per Mcfe were $2.62 for the year ended December 31, 2015, as compared
to $4.31 for the 2014 period. Stated on an Mcfe basis, unit prices received during the year ended December 31, 2015 were 35%
lower than the prices received during the 2014 period.

Revenue Including the effects of hedges, oil and gas sales during the twelve months ended December 31, 2015 decreased 48%
to $115,969,000, as compared to oil and gas sales of $225,021,000 during the 2014 period. The decreased revenue during 2015
was primarily due to decreased production during 2015 as a result of the Oklahoma Divestiture, as well as lower average realized
prices.

Expenses Lease operating expenses for the year ended December 31, 2015 totaled $40,130,000, or $1.17 per Mcfe, as compared
to $48,597,000, or $1.12 per Mcfe, during the 2014 period. The increase in per unit lease operating expenses for the year ended
December 31, 2015 is primarily a result of the Oklahoma Divestiture, which included properties with a lower relative per unit
cost, as well as normal production declines and downtime at certain of our Gulf Coast fields. We expect lease operating expenses
during 2016 to decrease as compared to 2015 expenses on an absolute value basis and increase on a per unit basis as a result of
the full year effect of the Oklahoma Divestiture.

Production taxes for the year ended December 31, 2015 totaled $2,470,000, or $0.07 per Mcfe, as compared to $5,927,000, or
$0.14 per Mcfe, during the 2014 period. The decrease in total production taxes was primarily due to lower commodity prices for
our production during the 2015 period as compared to the 2014 period. The majority of our properties that are subject to severance
taxes are assessed on the oil and gas sales value. As a result of the current commodity pricing environment, we expect a decrease
in our total and per unit production taxes during 2016 as compared to 2015.

General and administrative expenses during the year ended December 31, 2015 totaled $20,777,000 as compared to $22,870,000
during the 2014 period. General and administrative expenses decreased 9% during the year ended December 31, 2015 primarily
due to lower employee related costs including share-based compensation during the 2015 period which was only partially offset
by lower capitalized costs. Included in general and administrative expenses for 2015 are share-based compensation costs, net of
amounts capitalized, of $4,388,000, compared to $6,808,000 during the 2014 period. We capitalized $8,210,000 of general and
administrative costs during the year ended December 31, 2015 as compared to $12,122,000 during the comparable 2014 period.
We expect general and administrative expenses to decrease further in 2016.

Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the year ended December 31, 2015
totaled $62,138,000, or $1.82 per Mcfe, as compared to $86,406,000, or $1.99 per Mcfe, during the comparable 2014 period. The
decrease in the per unit DD&A rate is primarily the result of current year ceiling test write-downs. As a result of these write-
downs, we expect our DD&A rate for 2016 to be lower than the rate during 2015.

At December 31, 2015, the prices used in computing the estimated future net cash flows from our estimated proved reserves,
including the effect of hedges in place at that date, averaged $2.42 per Mcf of natural gas, $50.29 per barrel of oil and $2.21 per
Mcfe of natural gas liquids, respectively. As a result of lower commodity prices and their negative impact on our estimated proved
reserves and estimated future net cash flows, we recognized a ceiling test write-down of approximately $266,562,000 during the
year. See Note 12, "Ceiling Test" for further discussion of the ceiling test write-down. Utilizing current strip prices for oil and
gas prices for the first quarter of 2016 and projecting the effect on the estimated future net cash flows from our estimated proved
reserves as of March 31, 2016, we expect to recognize an additional ceiling test write-down of $20,000,000 to $40,000,000 during
the first quarter of 2016.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $33,766,000 during the year ended December 31,
2015, as compared to $29,281,000 during 2014. During the year ended December 31, 2015, our capitalized interest totaled
$4,671,000 as compared to $9,999,000 during the 2014 period. The increase in interest expense was a result of lower capitalized
interest on our reduced unevaluated property balance which declined as a result of the Oklahoma Divestiture. As a result of the
consummation of the Exchange Offer described in "Liquidity and Capital Resources - Sources of Capital: Debt" below, we expect
interest expense for 2016 to decrease compared to 2015.

Income tax expense (benefit) during the year ended December 31, 2015 totaled $2,626,000, as compared to ($2,941,000) during
the 2014 period. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to
be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.

As a result of the ceiling test write-downs recognized, we have incurred a cumulative three-year loss. Because of the impact the
cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the
realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established
a valuation allowance for a portion of our deferred tax asset. The valuation allowance was $143,508,000 as of December 31, 2015.
43

Comparison of Results of Operations for the Years Ended December 31, 2014 and 2013

Net income available to common stockholders totaled $26,051,000 and $8,943,000 for the years ended December 31, 2014 and
2013, respectively. The primary fluctuations were as follows:

Production Total production increased 14% during the year ended December 31, 2014 as compared to the 2013 period. The
increase in total production was due primarily to a full year of production from the wells acquired in the Gulf of Mexico Acquisition,
which closed on July 3, 2013, as well as our successful drilling programs in our Carthage field and the liquids rich portion of our
Oklahoma acreage position. Partially offsetting these increases were decreases in production due to normal production declines
at our dry gas Oklahoma fields as well as certain of our legacy Gulf Coast fields.

Gas production during the year ended December 31, 2014 increased 6% from the 2013 period. The increase in gas production was
due primarily to our successful drilling program in our Carthage field as well as a full year of production from the wells acquired
in the Gulf of Mexico Acquisition. Partially offsetting these increases were decreases in gas production due to normal production
declines at our dry gas Oklahoma fields as well as certain of our legacy Gulf Coast fields.

Oil production during the year ended December 31, 2014 increased 18% as compared to the 2013 period due primarily to a full
year of production from the wells acquired in the Gulf of Mexico Acquisition. Partially offsetting this increase were decreases as
a result of continued normal production declines in certain of our legacy Gulf Coast fields.

Ngl production during the year ended December 31, 2014 increased 57% from the 2013 period due to the successful drilling
programs in the liquids rich portion of our Oklahoma acreage position and in our Carthage field. Additionally, Ngl production
increased as a result of added production from the wells acquired in the Gulf of Mexico Acquisition. Partially offsetting these
increases were decreases as a result of normal production declines at our legacy Gulf Coast fields.

Prices Including the effects of our hedges, average gas prices per Mcf for the year ended December 31, 2014 were $3.69 as
compared to $2.99 for the 2013 period. Average oil prices per Bbl for the year ended December 31, 2014 were $97.41 as compared
to $103.49 for the 2013 period and average Ngl prices per Mcfe were $4.31 for the year ended December 31, 2014, as compared
to $5.23 for the 2013 period. Stated on an Mcfe basis, unit prices received during the year ended December 31, 2014 were 8%
higher than the prices received during the 2013 period.

Revenue Including the effects of hedges, oil and gas sales during the twelve months ended December 31, 2014 increased 23% to
$225,021,000, as compared to oil and gas sales of $182,804,000 during the 2013 period. The increased revenue during 2014 was
primarily the result of increased production during 2014 as well as higher average realized prices for our gas production, which
represents the majority of our total production.

Expenses Lease operating expenses for the year ended December 31, 2014 totaled $48,597,000, or $1.12 per Mcfe, as compared
to $43,743,000, or $1.15 per Mcfe, during the 2013 period. The decrease in per unit lease operating expenses for the year ended
December 31, 2014 is primarily due to increased production from our onshore properties which typically incur lower per unit
lease operating expenses.

Production taxes for the year ended December 31, 2014 totaled $5,927,000, or $0.14 per Mcfe, as compared to $3,950,000, or
$0.10 per Mcfe, during the 2013 period. The increase in total production taxes was primarily due to increased production from
onshore properties subject to severance taxes as well as an increase in Louisiana severance tax rates effective July 2014. The
majority of our properties that are subject to severance taxes are assessed on the oil and gas sales value.

General and administrative expenses during the year ended December 31, 2014 totaled $22,870,000 as compared to $26,512,000
during the 2013 period. General and administrative expenses decreased 14% during the year ended December 31, 2014 primarily
due to acquisition-related costs associated with the Gulf of Mexico Acquisition of $4,018,000 incurred during the 2013
period. Included in general and administrative expenses for 2014 are share-based compensation costs, net of amounts capitalized,
of $6,808,000, compared to $5,011,000 during the 2013 period. We capitalized $12,122,000 of general and administrative costs
during the year ended December 31, 2014 as compared to $13,342,000 during the comparable 2013 period.

DD&A expense on oil and gas properties for the year ended December 31, 2014 totaled $86,406,000, or $1.99 per Mcfe, as
compared to $69,357,000, or $1.82 per Mcfe, during the comparable 2013 period. The increase in the per unit DD&A rate is
primarily the result of the properties acquired in the Gulf of Mexico Acquisition, which had a higher cost per unit as compared to
our overall amortization base.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $29,281,000 during the year ended December 31,
2014, as compared to $21,886,000 during 2013. During the year ended December 31, 2014, our capitalized interest totaled

$9,999,000 as compared to $6,570,000 during the 2013 period. The increase in interest expense was a result of the issuance of
an additional $200 million of 10% senior notes in 2013, which were used to finance the Gulf of Mexico Acquisition.

Income tax expense (benefit) during the year ended December 31, 2014 totaled ($2,941,000), as compared to $320,000 during the
2013 period. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be
realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.

As a result of the ceiling test write-downs recognized during 2012, we have incurred a cumulative three-year loss. Because of the
impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed
the realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established
a valuation allowance for a portion of our deferred tax asset. The valuation allowance was $33,295,000 as of December 31, 2014.

Liquidity and Capital Resources

We have financed our acquisition, exploration and development activities to date principally through cash flow from
operations, bank borrowings, issuances of equity and debt securities, joint ventures and sales of assets. At December 31, 2015,
we had a working capital surplus of $50.5 million compared to a deficit of $80.2 million at December 31, 2014. The improvement
in our working capital is the result of proceeds received from the Oklahoma Divestiture, partially offset by the full repayment of
our bank credit facility. Since we operate the majority of our drilling activities, we have the ability to reduce our capital expenditures
to manage our working capital and liquidity position. In response to the impact that the decline in commodity prices has had, and
is expected to continue to have, on our cash flow, our 2016 capital expenditures budget has been significantly reduced as compared
to 2015 and we plan to fund it through cash flow from operations and cash on hand. To the extent additional capital is required,
we may utilize sales of equity or debt securities, evaluate the sale of additional assets, enter into joint venture arrangements or
reduce our capital expenditure budget to manage our liquidity position. In addition, we plan to suspend the quarterly dividend on
our outstanding Series B Preferred Stock beginning with the dividend payment in April 2016 (which will save $5.1 million
annually), reduce our cash costs by 25% from 2015 levels and consider additional options to refinance our remaining $135.6
million of 10% Senior Notes due 2017.

As of December 31, 2015, we had $148 million of cash on hand and had no borrowings outstanding under our bank credit
facility. We currently have $42 million of availability under our bank credit facility, subject to compliance with the financial
covenants thereunder, which, based on our expectations for the first quarter of 2016, will effectively limit the availability to 25%
of the aggregate commitment of the lenders, or $10.5 million.

Prices for oil and natural gas are subject to many factors beyond our control such as weather, the overall condition of the
global financial markets and economies, relatively minor changes in the outlook of supply and demand, and the actions of OPEC.
Oil and natural gas prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow
and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic re-determination based
in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can
economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under
the bank credit facility, thus reducing the amount of financial resources available to meet our capital requirements. Lower prices
and reduced cash flow may also make it difficult to incur debt, including under our bank credit facility, because of the restrictive
covenants in the indenture governing the 10% senior secured notes. See “Source of Capital: Debt” below. Our ability to comply
with the covenants in our debt agreements is dependent upon the success of our exploration and development program and upon
factors beyond our control, such as oil and natural gas prices.

Source of Capital: Operations

Net cash flow from operations decreased from $178.2 million during the year ended December 31, 2014 to $30.1 million
during the 2015 period. The decrease in operating cash flow during 2015 as compared to 2014 was primarily attributable to
decreases in oil and gas revenues as well as the timing of payment of payables based on increased operational activity.

Source of Capital: Debt

On August 19, 2010, the Company issued $150 million in principal amount of its 10% Senior Notes due 2017 and on
July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (collectively,
the "Old Notes"). The Old Notes are guaranteed by certain of PetroQuest's subsidiaries. The subsidiary guarantors are 100% owned
by PetroQuest and all guarantees are full and unconditional and joint and several. PetroQuest has no independent assets or operations
and the subsidiaries not providing guarantees are minor, as defined by the rules of the Securities and Exchange Commission.

Interest on the Old Notes is payable semi-annually on March 1 and September 1. At December 31, 2015, $11.7 million
had been accrued in connection with the March 1, 2016 interest payment (which amount has been reduced to $4.5 million as a

result of the Exchange Offering), and the Company was in compliance with all of the covenants then contained in the indenture
governing the Old Notes.

On February 17, 2016, the Company completed a private offering to exchange (the “Exchange Offering”) up to $300
million aggregate principal amount of the Old Notes and related consent solicitation (the “Consent Solicitation”) to amend and
waive certain provisions of the indenture governing the Old Notes. At the closing, and in satisfaction of the consideration for
$214,379,000 in aggregate principal amount of the Old Notes, representing approximately 61% of the outstanding aggregate
principal amount of Old Notes, validly tendered (and not validly withdrawn) in the Exchange Offering, the Company (i) paid
approximately $53.6 million of cash, (ii) issued $144,674,000 aggregate principal amount of its newly issued 10% senior secured
notes and (iii) issued 4,287,580 shares of its common stock.

The indenture governing the 10% senior secured notes contains affirmative and negative covenants that, among other
things, limit the ability of the Company and the subsidiary guarantors of the 10% senior secured notes to incur indebtedness;
purchase or redeem stock; make certain investments; create liens that secure debt; enter into transactions with affiliates; sell assets;
refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain
circumstances, to pay dividends or make other distributions on stock. The 10% senior secured notes are fully and unconditionally
guaranteed on a senior basis by certain wholly-owned subsidiaries of the Company.

The Company will pay 10% interest per annum on the principal amount of the 10% senior secured notes, semi-annually

in arrears on February 15 and August 15 of each year.

The 10% senior secured notes are secured by second-priority liens on substantially all of the Company’s and the subsidiary
guarantors’ oil and gas properties and substantially all of their other assets to the extent such properties and assets secure the Credit
Agreement (as defined below), except for certain excluded assets. Pursuant to the terms of an intercreditor agreement, the security
interest in those properties and assets that secure the 10% senior secured notes and the guarantees are contractually subordinated
to liens that secure the Credit Agreement and certain other permitted indebtedness. Consequently, the 10% senior secured notes
and the guarantees will be effectively subordinated to the Credit Agreement and such other indebtedness to the extent of the value
of such assets.

As a result of the Consent Solicitation, the indenture governing the Old Notes was amended such that substantially all

of the restrictive covenants were eliminated or waived.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit
Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A.
and The Bank of Nova Scotia. The Credit Agreement provides the Company with a $300 million revolving credit facility that
permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with
the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters
of credit. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of the Old Notes remain
outstanding as of such date which has not been refinanced with either permitted refinancing debt or permitted second lien debt
with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement. As of December 31, 2015
the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is determined by March 31 and September 30 of each year and based
upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. As
of December 31, 2015, the borrowing base was $55 million (subject to the aggregate commitments of the lenders then in effect
and our compliance with the financial covenants thereunder). During January 2016, the borrowing base and the aggregate
commitments of the lenders were reduced to $42 million. Based on the Company’s expectations for the first quarter of 2016, the
Company anticipates that, pursuant to the applicable financial covenants the Company’s utilization of the borrowing base will be
limited to 25% of the aggregate commitments of the lenders, or $10.5 million. The next scheduled borrowing base redetermination
is scheduled to occur by March 31, 2016 with additional interim redeterminations to occur on July 31 and December 31 of each
year, commencing on July 31, 2016. The Company or the lenders may request two additional borrowing base re-determinations
each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose
a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base
is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base
remains the same or is reduced.

11:00 a.m. London time on such day. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits
in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory
reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate
equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company
pays commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.

The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement,
including (i) a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of (a) if the Company has
unused availability greater than or equal to 75% of the aggregate commitments of the Lenders at all times during the consecutive
three month period prior to and including the date of each fiscal quarter end, the maximum ratio of total debt to EBITDAX is 5.0
to 1.0 as of the last day of the fiscal quarter ending March 31, 2016, 5.5 to 1.0 as of the last day of the fiscal quarter ending June
30, 2016 and 5.75 to 1.0 as of the last day of the fiscal quarters ending September 30, 2016 and December 31, 2016, with in each
case the amount of total debt for such quarterly period reduced by the amount of unencumbered and unrestricted cash of the
Company and cash subject to an account control agreement, (b) if the Company has unused availability of less than 75% of the
aggregate commitments of the Lenders at any time during the consecutive three month period prior to and including the date of
calculating the ratio, the maximum ratio of total debt to EBITDAX will be 5.75 to 1.00 as of the last day of the fiscal quarters
ending March 31, 2016, June 30, 2016 and September 30, 2016 and 5.25 to 1.00 as of the last day of the fiscal quarter ending
December 31, 2016, and (c) 5.00 to 1.00 as of the last day of any fiscal quarter ending on or after March 31, 2017 and (ii) a
minimum ratio of EBITDAX to total cash interest expense of 1.0 to 1.0, all as defined in the Credit Agreement.

In addition, the Credit Agreement permits a sale of the majority of the Company’s remaining oil and gas assets in Oklahoma,
provided that such sale is consummated on or prior to March 31, 2016, all of the consideration received in such sale is cash, and
the borrowing base will be reduced by $10 million upon the consummation of such sale. The Credit Agreement currently prohibits
the Company from declaring and paying dividends on its Series B Preferred Stock.

The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and
redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale
or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements,
gas imbalances and swap agreements. As of December 31, 2015, the Company was in compliance with all such covenants contained
in the Credit Agreement.

As a result of the impact of the decline in commodity prices, we anticipate that we may exceed the maximum ratio of
total debt to EBITDAX financial covenant included in the Credit Agreement as early as the end of the first quarter of 2016, which
would require us to seek a waiver or amendment from the lenders. We cannot provide any assurances that we will be able to reach
an agreement with the lenders on an amendment or waiver on a timely basis or on satisfactory terms to alleviate any non-compliance
with the financial covenants under the Credit Agreement.

Source of Capital: Issuance of Securities

Our shelf registration statement allows us to publicly offer and sell up to $350 million of any combination of debt securities,
shares of common and preferred stock, depositary shares and warrants. The registration statement does not provide any assurance
that we will or could sell any such securities.

Source of Capital: Divestitures

We do not budget property divestitures; however, we are continuously evaluating our property base to determine if there
are assets in our portfolio that no longer meet our strategic objectives. From time to time we may divest certain assets in order to
provide liquidity to strengthen our balance sheet or provide capital to be reinvested in higher rate of return projects. We are currently
exploring divestment opportunities for certain of our legacy Gulf of Mexico assets. We cannot assure you that we will be able to
sell any of our assets in the future.

In January 2013, we sold 50% of our saltwater disposal systems and related surface assets in the Woodford for net proceeds
of approximately $10 million. In December 2013, we sold our non-operated Wyoming assets for a cash purchase price of $1.0
million. In September 2014, we sold our Eagle Ford assets for net proceeds of approximately $9.8 million. In 2015, we sold the
majority of our Oklahoma assets for net proceeds of approximately $274.1 million as well as our Fort Trinidad and East Haynesville
assets for net proceeds of approximately $0.5 million and $0.1 million, respectively.

Use of Capital: Exploration and Development

Our 2016 capital budget, which includes capitalized interest and general and administrative costs, is expected to range
between $20 million and $25 million, which from the midpoint of such range, represents a 65% reduction from our 2015 capital
expenditures in response to weaker commodity prices. Because we operate the majority of our drilling activities, we expect to be
able to control the timing of a substantial portion of our capital investments. We plan to fund our capital expenditures with cash

flow from operations and cash on hand. To the extent additional capital is required, we may utilize sales of equity or debt securities,
evaluate the sale of additional assets or we may reduce our capital expenditures to manage our liquidity position.

Use of Capital: Acquisitions

On July 3, 2013, we closed the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8 million. The

acquired assets include 16 gross wells located on seven platforms.

We do not budget acquisitions; however, we are continuously evaluating opportunities to expand our existing asset base

or establish positions in new core areas.

We expect to finance our future acquisition activities, if consummated, through cash on hand or available borrowings
under our bank credit facility. We may also utilize sales of equity or debt securities, sales of properties or assets or joint venture
arrangements with industry partners, if necessary. We cannot assure you that such additional financings will be available on
acceptable terms, if at all.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2015 (in thousands):

10% senior notes (1)

Operating leases (2)

Asset retirement obligations (3)

Acquisition Costs (4)

Total

2016

2017

2018

2019

2020

After 2020

$408,333

$ 35,000

$373,333

— $

5,245

42,556

4,409

1,419

6,015

4,409

1,310

6,343

—

452

1,539

—

422

589

—

417

23,975

—

1,225

4,095

—

$460,543

$ 46,843

$380,986

1,991

1,011

$ 24,392

5,320

(1) Includes principal and estimated interest.
(2) Consists primarily of leases for office space and office equipment.
(3) Consists of estimated future obligations to abandon our oil and gas properties.
(4) Consists of amounts payable related to the Fleetwood Joint Venture

As a result of the Exchange Offering described above, we reduced our annual fixed charges by $7 million and eliminated
or extended the maturity date on 61% of our $350 million of indebtedness as of December 31, 2015. After completion of the
Exchange Offering, we have $280.3 million of total indebtedness with $135.6 million maturing in September 2017 and $144.7
million maturing in February 2021.

The following table summarizes our contractual obligations as of the date of this report (in thousands):

Total

2016

2017

2018

2019

2020

After 2020

10% senior notes (1)

$156,454

7,271

$149,183

— $

—

10% senior secured notes (1)

Operating leases (2)

Asset retirement obligations (3)

212,191

5,245

42,556

7,756

1,419

6,015

14,468

146,563

1,310

6,343

452

1,539

422

589

417

23,975

1,225

4,095

Total

$416,446

$ 22,461

$171,304

$ 16,459

$ 15,479

$ 38,860

$ 151,883

Item 7A Quantitative and Qualitative Disclosures About Market Risk

We experience market risks primarily in two areas: interest rates and commodity prices. Because all of our properties are
located within the United States, we believe that our business operations are not exposed to significant market risks relating to
foreign currency exchange risk.

Our revenues are derived from the sale of our crude oil, natural gas, and natural gas liquids production. Based on projected
annual sales volumes for 2016, a 10% decline in the estimated average prices we expect to receive for our crude oil, natural gas
and natural gas liquids production would result in an approximate $4.9 million decline in our revenues for 2016.

We periodically seek to reduce our exposure to commodity price volatility by hedging a portion of production through
commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the
counterparties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index,
multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this
difference multiplied by the quantity hedged. During the year ended December 31, 2015, we received approximately $17.1 million
from the counterparties to our derivative instruments in connection with net hedge settlements.

We are required to pay the difference between the floating price and the fixed price (when the floating price exceeds the
fixed price) regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions
in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements
even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage
of increases in oil or gas prices above the fixed amount specified in the hedge.

Our Credit Agreement requires that the counterparties to our hedge contracts be lenders under the Credit Agreement or,
if not a lender under the Credit Agreement, rated A/A2 or higher by S&P or Moody’s. Currently, the counterparties to our existing
hedge contracts are JPMorgan Chase Bank and The Bank of Nova Scotia, both of whom are lenders under the Credit Agreement.
To the extent we enter into additional hedge contracts, we would expect that certain of the lenders under the Credit Agreement
would serve as counterparties.

As of December 31, 2015, we had entered into the following gas hedge contract:

Production Period
Natural Gas:
January 2016 - June 2016 Swap

Instrument Type Daily Volumes Weighted Average Price

10,000 Mmbtu

$3.22

During January 2016, we entered into the following additional hedge contract accounted for as a cash flow hedge:

Production Period

Instrument Type Daily Volumes Weighted Average Price

Natural Gas:

July 2016 - December 2016

Swap

5,000 Mmbtu

$2.50

After executing the above transactions, the Company has approximately 2.7 Bcf of gas volumes, at an average price of
$2.98 per Mcf hedged for 2016, which represents 10% of our 2016 estimated production assuming the midpoint of our first quarter
2016 production guidance is held constant for the remainder of the year.

Item 8.

Financial Statements and Supplementary Data

Information concerning this Item begins on page F-1.

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, the Company’s management, including its Chief Executive Officer
and Chief Financial Officer, carried out an evaluation of the effectiveness of the Company’s disclosure controls and procedures
pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer
concluded the following:

that the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be
disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such
information is accumulated and communicated to the Company’s management, including the Chief Executive
Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and

ii.

that the Company’s disclosure controls and procedures are effective.

Notwithstanding the foregoing, there can be no assurance that the Company’s disclosure controls and procedures will
detect or uncover all failures of persons within the Company and its consolidated subsidiaries to disclose material information
otherwise required to be set forth in the Company’s periodic reports. There are inherent limitations to the effectiveness of any
system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the
controls and procedures.

Changes in Internal Control Over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting during the quarter ended
December 31, 2015 that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control
over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, and for
performing an assessment of the effectiveness of internal control over financial reporting as of December 31, 2015. Internal control
over financial reporting is a process designed 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. Our
system of internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made
only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have
a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management performed an assessment of the effectiveness of our internal control over financial reporting as of
December 31, 2015 based upon criteria in Internal Control – Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework). Based on our assessment, management believes that our internal
control over financial reporting was effective as of December 31, 2015 based on these criteria.

Ernst & Young LLP, our independent registered public accounting firm, has issued their report on the effectiveness of

the Company's internal control over financial reporting as of December 31, 2015.

March 4, 2016

/s/ Charles T. Goodson
Charles T. Goodson
Chairman and
Chief Executive Officer

/s/ J. Bond Clement
J. Bond Clement
Executive Vice President-
Chief Financial Officer

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
PetroQuest Energy, Inc.

We have audited PetroQuest Energy, Inc.’s internal control over financial reporting as of December 31, 2015, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework) (the COSO criteria). PetroQuest Energy, Inc.’s management is responsible for
maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over
financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our
responsibility is to express an opinion on the Company’s internal control over financial reporting 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 effective internal
control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in
the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, PetroQuest Energy, Inc. maintained, in all material respects, effective internal control over financial

reporting as of December 31, 2015, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the accompanying consolidated balance sheets of PetroQuest Energy, Inc. as of December 31, 2015 and 2014, and the
related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the
three years in the period ended December 31, 2015 and our report dated March 4, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana
March 4, 2016

Item 9B.

Other Information

NONE

Items 10, 11, 12, 13, & 14.

PART III

Pursuant to General Instruction G of Form 10-K, the information concerning Item 10. Directors, Executive Officers
and Corporate Governance, Item 11. Executive Compensation, Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters, Item 13. Certain Relationships and Related Transactions, and Director
Independence and Item 14. Principal Accounting Fees and Services, is incorporated by reference to the information set forth in
the definitive Proxy Statement of PetroQuest Energy, Inc. relating to the Annual Meeting of Stockholders to be held May 18, 2016,
to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 with the Securities and Exchange Commission.

Item 15.

Exhibits, Financial Statement Schedules

(a) 1. FINANCIAL STATEMENTS

PART IV

The following financial statements of the Company and the Report of the Company’s Independent Registered Public

Accounting Firm thereon are included on pages F-1 through F-27 of this Form 10-K:

Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2015 and 2014
Consolidated Statements of Operations for the three years ended December 31, 2015
Consolidated Statements of Comprehensive Income (Loss) for the three years ended December 31, 2015
Consolidated Statements of Cash Flows for the three years ended December 31, 2015
Consolidated Statements of Stockholders’ Equity for the three years ended December 31, 2015
Notes to Consolidated Financial Statements

2. FINANCIAL STATEMENT SCHEDULES:

All schedules are omitted because the required information is inapplicable or the information is presented in the Financial

Statements or the notes thereto.

EXHIBITS:

** 2.1

** 2.2

** 2.3

** 2.4

** 2.5

**#2.6

3.1

3.2

3.3

3.4

3.5

3.6

4.1

4.2

4.3

4.5

Plan and Agreement of Merger by and among Optima Petroleum Corporation, Optima Energy
(U.S.) Corporation, its wholly-owned subsidiary, and Goodson Exploration Company, NAB
Financial L.L.C., Dexco Energy, Inc., American Explorer, L.L.C. (incorporated herein by reference
to Appendix G of the Proxy Statement on Schedule 14A filed July 22, 1998).

Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and
Hall-Houston Exploration II, L.P. (incorporated herein by reference to Exhibit 2.1 to Form 8-K
filed on June 20, 2013).

Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and
Hall-Houston Exploration III, L.P. (incorporated herein by reference to Exhibit 2.2 to Form 8-K
filed on June 20, 2013).

Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and
Hall-Houston Exploration IV, L.P. (incorporated herein by reference to Exhibit 2.3 to Form 8-K
filed on June 20, 2013).

Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and
GOM-H Exploration, LLC (incorporated herein by reference to Exhibit 2.4 to Form 8-K filed on
June 20, 2013).

Purchase and Sale Agreement dated as of June 4, 2015, by and between PetroQuest Energy, L.L.C.
and WSGP Gas Producing, LLC (incorporated herein by reference to Exhibit 2.1 to Form 10-Q
filed on August 5, 2015).

Certificate of Incorporation of PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit
4.1 to Form 8-K filed September 16, 1998).

Certificate of Amendment to Certificate of Incorporation dated May 14, 2008 (incorporated herein
by reference to Exhibit 3.1 to Form 8-K filed June 23, 2009).

Bylaws of PetroQuest Energy, Inc., as amended of February 19, 2016 (incorporated herein by
reference to Exhibit 3.1 to Form 8-K filed February 22, 2016).

Certificate of Domestication of Optima Petroleum Corporation (incorporated herein by reference to
Exhibit 4.4 to Form 8-K filed September 16, 1998).

Certificate of Designations, Preferences, Limitations and Relative Rights of The Series a Junior
Participating Preferred Stock of PetroQuest Energy, Inc. (incorporated herein by reference to
Exhibit A of the Rights Agreement attached as Exhibit 1 to Form 8-A filed November 9, 2001).

Certificate of Designations establishing the 6.875% Series B Cumulative Convertible Perpetual
Preferred Stock, dated September 24, 2007 (incorporated herein by reference to Exhibit 3.1 to Form
8-K filed on September 24, 2007).

Rights Agreement dated as of November 7, 2001 between PetroQuest Energy, Inc. and American
Stock Transfer & Trust Company, as Rights Agent, including exhibits thereto (incorporated herein
by reference to Exhibit 1 to Form 8-A filed November 9, 2001).

Form of Rights Certificate (incorporated herein by reference to Exhibit C of the Rights Agreement
attached as Exhibit 1 to Form 8-A filed November 9, 2001).

Indenture, dated August 19, 2010, between PetroQuest Energy, Inc. and The Bank of New York
Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on
August 19, 2010).

First Supplemental Indenture, dated August 19, 2010, among PetroQuest Energy, Inc., the
Subsidiary Guarantors identified therein, and The Bank of New York Mellon Trust Company, N.A.
(incorporated herein by reference to Exhibit 4.3 to Form 8-K filed on August 19, 2010).

4.6

4.7

4.8

4.9

4.10

4.11

†10.1

†10.2

†10.3

†10.4

†10.5

†10.6

†10.7

†10.8

†10.9

Second Supplemental Indenture, dated July 3, 2013, among PetroQuest Energy, Inc., the Subsidiary
Guarantors identified therein, and The Bank of New York Mellon Trust Company, N.A.
(incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on July 3, 2013).

Third Supplemental Indenture, dated October 23, 2013, among PetroQuest Energy, Inc., the
Subsidiary Guarantors identified therein, and The Bank of New York Mellon Trust Company, N.A.
(incorporated herein by reference to Exhibit 4.7 to Form 10-K filed on March 6, 2015)

Fourth Supplemental Indenture, dated February 1, 2015, among PetroQuest Energy, Inc., the
Subsidiary Guarantors identified therein, and U.S. Bank National Association, as successor trustee
to The Bank of New York Mellon Trust Company, N.A. (incorporated herein by reference to
Exhibit 4.1 to Form 8-K filed on February 3, 2016).

Indenture, dated February 17, 2016, between PetroQuest Energy, Inc., the Subsidiary Guarantors
identified therein, and Wilmington Trust, National Association (incorporated herein by reference to
Exhibit 4.1 to Form 8-K filed on February 18, 2016).

Registration Rights Agreement, dated July 3, 2013, among PetroQuest Energy, Inc., the Subsidiary
Guarantors identified therein, and J.P. Morgan Securities LLC, as representative of the several
initial purchasers named therein (incorporated herein by reference to Exhibit 4.3 to Form 8-K filed
on July 3, 2013).

Registration Rights Agreement, dated February 17, 2016, among PetroQuest Energy, Inc., the
Subsidiary Guarantors identified therein, and Seaport Global Securities LLC, as representative of
the several investors named therein (incorporated herein by reference to Exhibit 4.2 to Form 8-K
filed on February 18, 2016).

PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated effective May 14, 2008 (the
“Incentive Plan”) (incorporated herein by reference to Appendix A of the Proxy Statement on
Schedule 14A filed April 9, 2008).

Form of Incentive Stock Option Agreement for executive officers (including Charles T. Goodson,
Arthur M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under the PetroQuest
Energy, Inc. 1998 Incentive Plan (incorporated herein by reference to Exhibit 10.2 to Form 10-K
filed February 27, 2009).

Form of Nonstatutory Stock Option Agreement under the PetroQuest Energy, Inc. 1998 Incentive
Plan (incorporated herein by reference to Exhibit 10.3 to Form 10-K filed February 27, 2009).

Form of Restricted Stock Agreement for executive officers (including Charles T. Goodson, Arthur
M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under the PetroQuest
Energy, Inc. 1998 Incentive Plan (incorporated herein by reference to Exhibit 10.4 to Form 10-K
filed February 27, 2009).

PetroQuest Energy, Inc. Annual Incentive Plan (incorporated herein by reference to Exhibit 10.1 to
Form 8-K filed on May 13, 2010).

PetroQuest Energy, Inc. Annual Incentive Plan, as amended and restated (incorporated herein by
reference to Exhibit 10.1 to Form 8-K filed on June 8, 2010).

PetroQuest Energy, Inc. 2012 Employee Stock Purchase Plan (incorporated herein by reference to
Appendix A to Schedule 14A filed March 28, 2012).

PetroQuest Energy, Inc. Long-Term Cash Incentive Plan (incorporated herein by reference to
Exhibit 10.1 to Form 8-K filed November 15, 2012).

PetroQuest Energy, Inc. 2013 Incentive Plan (incorporated herein by reference to Appendix A to the
Company’s Definitive Proxy Statement on Schedule 14A filed on April 9, 2013).

†10.10

†10.11

†10.12

†10.13

†10.14

†10.15

10.16

10.17

10.18

10.19

10.20

10.21

10.22

Form of Award Notice of Restricted Stock Units - Employees (including Charles T. Goodson,
Arthur M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under the PetroQuest
Energy, Inc. Long-Term Cash Incentive Plan (incorporated herein by reference to Exhibit 10.2 to
Form 8-K filed November 15, 2012).

Form of Award Notice of Restricted Stock Units - Outside Director/Consultant under the
PetroQuest Energy, Inc. Long-Term Cash Incentive Plan (incorporated herein by reference to
Exhibit 10.3 to Form 8-K filed November 15, 2012).

Form of Restricted Stock Agreement - Executive Officers (including Charles T. Goodson, Arthur
M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under the PetroQuest
Energy, Inc. 1998 Incentive Plan (incorporated herein by reference to Exhibit 10.4 to Form 8-K
filed November 15, 2012).

Form of Restricted Stock Units Agreement - Employees (including Charles T. Goodson, Arthur M.
Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under the PetroQuest Energy,
Inc. 2013 Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed
November 19, 2014).

Form of Award Notice of Phantom Stock Units - Employees (including Charles T. Goodson, Arthur
M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under the PetroQuest
Energy, Inc. Long-Term Cash Incentive Plan (incorporated herein by reference to Exhibit 10.2 to
Form 8-K filed November 19, 2014).

Form of Performance Unit Notice and Award- Employees (including Charles T. Goodson, Arthur
M. Mixon, III, J. Bond Clement, Tracy Price and Edward E. Abels, Jr.) under the PetroQuest
Energy, Inc. Long-Term Cash Incentive Plan (incorporated herein by reference to Exhibit 10.1 to
Form 8-K filed November 21, 2014).

Credit Agreement dated as of October 2, 2008, among PetroQuest Energy, L.L.C., PetroQuest
Energy, Inc., JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A.,
Wells Fargo Bank, N.A., and Whitney National Bank (incorporated herein by reference to Exhibit
10.1 to Form 8-K filed October 6, 2008).

First Amendment to Credit Agreement dated as of March 24, 2009, among PetroQuest Energy, Inc.,
PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Calyon New York
Branch, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney National Bank (incorporated
herein by reference to Exhibit 10.1 to Form 8-K filed March 24, 2009).

Second Amendment to Credit Agreement dated as of September 30, 2009, among PetroQuest
Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Calyon
New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney National Bank
(incorporated herein by reference to Exhibit 10.1 to Form 8-K filed October 1, 2009).

Third Amendment to Credit Agreement dated as of August 5, 2010, among PetroQuest Energy, Inc.,
PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Credit Agricole
Corporate and Investment Bank, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney
National Bank (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on August 6,
2010).

Fourth Amendment to Credit Agreement dated as of October 3, 2011, among PetroQuest Energy,
Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Wells Fargo
Bank, N.A., Capital One, N.A., Iberiabank and Whitney Bank (incorporated herein by reference to
Exhibit 10.1 to the Form 8-K filed on October 4, 2011).

Fifth Amendment to Credit Agreement dated as of March 29, 2013, among PetroQuest Energy, Inc.,
PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One,
N.A., IBERIABANK and Whitney Bank (incorporated herein by reference to Exhibit 10.1 to the
Form 8-K filed on March 29, 2013).

Sixth Amendment to Credit Agreement dated as of June 19, 2013, among PetroQuest Energy, Inc.,
PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One,
N.A., IBERIABANK and Whitney Bank (incorporated herein by reference to Exhibit 10.1 to the
Company’s Current Report on Form 8-K filed on June 20, 2013).

10.23

10.24

10.25

10.26

10.27

10.28

10.29

†10.30

†10.31

†10.32

†10.33

†10.34

Seventh Amendment to Credit Agreement dated as of March 31, 2014, among PetroQuest Energy,
Inc., PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital
One, N.A., Iberiabank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein
by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 31,
2014).

Eighth Amendment to Credit Agreement dated as of September 29, 2014, among PetroQuest
Energy, Inc., PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A.,
Capital One, N.A., Iberiabank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated
herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on
September 30, 2014).

Ninth Amendment to Credit Agreement dated as of February 26, 2015, among PetroQuest Energy,
Inc., PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital
One, N.A., Iberiabank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein
by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 26,
2015).

Tenth Amendment to Credit Agreement dated as of March 27, 2015, among PetroQuest Energy,
Inc., PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital
One, N.A., Iberiabank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein
by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 30,
2015).

Eleventh Amendment to Credit Agreement dated as of June 4, 2015, among PetroQuest Energy,
Inc., PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital
One, N.A., Iberiabank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein
by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 5, 2015).

Twelfth Amendment to Credit Agreement dated as of September 8, 2015, among PetroQuest
Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Wells
Fargo Bank, N.A., Capital One, N.A., Iberiabank, Bank of America, N.A. and The Bank of Nova
Scotia (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form
8-K filed on September 8, 2015).

Thirteenth Amendment to Credit Agreement dated as of January 25, 2016, among PetroQuest
Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC, JPMorgan Chase Bank, N.A., Wells
Fargo Bank, N.A., Capital One, National Association, IBERIABANK, Bank of America, N.A. and
The Bank of Nova Scotia (incorporated herein by reference to Exhibit 10.1 to the Company’s
Current Report on Form 8-K filed on January 26, 2016).

Amended Executive Employment Agreement dated effective as of December 31, 2008, between
Charles T. Goodson and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.1
to Form 8-K filed January 6, 2009).

Amended Executive Employment Agreement dated effective as of December 31, 2008, between
Arthur M. Mixon, III and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.3
to Form 8-K filed January 6, 2009).

Amended Executive Employment Agreement dated effective as of December 31, 2008, between J.
Bond Clement and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.20 to
Form 10-K filed February 27, 2009).

Executive Employment Agreement dated May 8, 2012 between PetroQuest Energy, Inc. and Tracy
Price (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed May 10, 2012).

Executive Employment Agreement dated February 1, 2014 between PetroQuest Energy, Inc. and
Edward E. Abels, Jr. (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed February
5, 2014).

†10.35

†10.36

†10.37

†10.38

†10.39

10.40

*10.41

10.42

10.43

10.44

Form of Amended Termination Agreement between the Company and each of its executive officers,
including Charles T. Goodson, Arthur M. Mixon, III, and J. Bond Clement (incorporated herein by
reference to Exhibit 10.6 to Form 8-K filed January 6, 2009).

Termination Agreement dated May 8, 2012 between PetroQuest Energy, Inc. and Tracy Price
(incorporated herein by reference to Exhibit 10.2 to Form 8-K filed May 10, 2012).

Termination Agreement dated February 1, 2014 between PetroQuest Energy, Inc. and Edward E.
Abels, Jr. (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed February 5, 2014).

Form of Indemnification Agreement between PetroQuest Energy, Inc. and each of its directors and
executive officers, including Charles T. Goodson, Arthur M. Mixon, III, , J. Bond Clement, Tracy
Price, Edward E. Abels, Jr., William W. Rucks, IV, E. Wayne Nordberg, Michael L. Finch, W.J.
Gordon, III and Charles F. Mitchell, II (incorporated herein by reference to Exhibit 10.21 to Form
10-K filed March 13, 2002).

Form of Surrender and Cancellation Agreement for Directors and Executive Officers (incorporated
herein by reference to Exhibit 10.1 to Form 8-K filed on September 16, 2010).

Joint Development Agreement dated May 17, 2010, among PetroQuest Energy, L.L.C., a Louisiana
limited liability company, WSGP Gas Producing, LLC, a Delaware limited liability company, and
NextEra Energy Gas Producing, LLC, a Delaware limited liability company (incorporated herein
by reference to Exhibit 10.2 to Form 10-Q filed on August 5, 2010).

First Amendment to the Joint Development Agreement dated May 17, 2010, among PetroQuest
Energy, L.L.C., a Louisiana limited liability company, WSGP Gas Producing, LLC, a Delaware
limited liability company, and NextEra Energy Gas Producing, LLC, a Delaware limited liability
company.

Second Amendment to the Joint Development Agreement dated February 24, 2012, among
PetroQuest Energy, L.L.C., a Louisiana limited liability company, WSGP Gas Producing, LLC, a
Delaware limited liability company, and NextEra Energy Gas Producing, LLC, a Delaware limited
liability company (incorporated herein by reference to Exhibit 10.22 to Form 10-K filed March 5,
2012).

Collateral Trust Agreement, dated February 17, 2016, among PetroQuest Energy, Inc., the
guarantors from time to time party thereto, Wilmington Trust, National Association, as Trustee, the
other Parity Lien Debt Representatives from time to time party thereto and Wilmington Trust,
National Association, as Collateral Trustee (incorporated herein by reference to Exhibit 10.1 to
Form 8-K filed on February 18, 2016).

Intercreditor Agreement, dated February 17, 2016, by and between JPMorgan Chase Bank, N.A., as
Priority Lien Agent, and Wilmington Trust, National Association, as Second Lien Collateral Trustee
(incorporated herein by reference to Exhibit 10.2 to Form 8-K filed on February 18, 2016).

14.1

Code of Business Conduct and Ethics (incorporated herein by reference to Exhibit 14.1 to Form
10-K filed March 8, 2006).

*21.1

Subsidiaries of the Company.

*23.1

Consent of Independent Registered Public Accounting Firm.

*23.2

Consent of Ryder Scott Company, L.P.

*31.1

*31.2

*32.1

*32.2

Certification of Chief Executive Officer pursuant to Rule 13-a-14(a) / Rule 15d-14(a),
promulgated under the Securities Exchange Act of 1934, as amended.

Certification of Chief Financial Officer pursuant to Rule 13-a-14(a) / Rule 15d-14(a), promulgated
under the Securities Exchange Act of 1934, as amended.

Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, of Chief Executive Officer.

Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, of Chief Financial Officer.

*99.1

Reserve report letter as of December 31, 2015, as prepared by Ryder Scott Company, L.P.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Definitions Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

*
**

†

Filed herewith.
The registrant agrees to furnish supplementally a copy of any omitted schedule to the Agreements to the SEC upon
request.

Management contract or compensatory plan or arrangement

Confidential treatment has been granted for portions of this exhibit. Omissions are designated with brackets containing
asterisks. As part of our confidential treatment request, a complete version of this exhibit was filed separately with the
SEC.

(b) Exhibits. See Item 15 (a) (3) above.
(c) Financial Statement Schedules. None

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas used in this Form 10-K.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate

or natural gas liquids.

Block. A block depicted on the Outer Continental Shelf Leasing and Official Protraction Diagrams issued by the U.S.
Minerals Management Service or a similar depiction on official protraction or similar diagrams issued by a state bordering on the
Gulf of Mexico.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree

Fahrenheit.

Completion. 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.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure,

but that, when produced, is in the liquid phase at surface pressure and temperature.

Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for
each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation
procedure.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon

known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the

sale of such production 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 oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a
service well, or a stratigraphic test well as those items are defined in this section.

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

Farm-in or farm-out. An agreement under which the owner of a working interest in a natural gas and oil lease assigns
the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor
is a "farm-out."

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual

geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Lead. A specific geographic area which, based on supporting geological, geophysical or other data, is deemed to have

potential for the discovery of commercial hydrocarbons.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. Thousand cubic feet of natural gas.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,

condensate or natural gas liquids.

MMBls. Million barrels of crude oil or other liquid hydrocarbons.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,

condensate or natural gas liquids.

Ngl. Natural gas liquid.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells, as the case may be.

Possible reserves. Those additional reserves that are less certain to be recovered than probable reserves.

Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of
values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a
full range of possible outcomes and their associated probabilities of occurrence.

Probable reserves. Those additional reserves that are less certain to be recovered than proved reserves but which, together

with proved reserves, are as likely as not to be recovered.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds

from the sale of such production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary
economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial
hydrocarbons.

Proved area. The part of a property to which proved reserves have been specifically attributed.

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

Proved properties. Properties with proved reserves.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the
quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually
recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved
than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and
economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase
or remain constant than to decrease.

Reliable technology. A grouping of one or more technologies (including computational methods) that has been field tested
and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated
or in an analogous formation.

Reserves. Estimated remaining quantities of oil and 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

gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resources. Quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources
may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered
and undiscovered accumulations.

Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes
of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection,
observation, or injection for in-situ combustion.

Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic

condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production.

Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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 acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the

production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Unproved properties. Properties with no proved reserves

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities

on the property and receive a share of production.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused

this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 4, 2016.

SIGNATURES

PETROQUEST ENERGY, INC.

By:

/s/ Charles T. Goodson

CHARLES T. GOODSON

Chairman of the Board, President and Chief
Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following

persons on behalf of the registrant and in the capacities indicated on March 4, 2016.

By:

/s/ Charles T. Goodson
CHARLES T. GOODSON

Chairman of the Board, President, Chief Executive Officer and Director
(Principal Executive Officer)

/s/ J. Bond Clement
J. BOND CLEMENT

Executive Vice President, Chief Financial Officer, Treasurer
(Principal Financial and Accounting Officer)

/s/ W.J. Gordon, III
W.J. GORDON, III

/s/ Michael L. Finch
MICHAEL L. FINCH

Director

/s/ Charles F. Mitchell, II, M.D. Director
CHARLES F. MITCHELL, II,
M.D.

/s/ E. Wayne Nordberg
E. WAYNE NORDBERG

Director

/s/ William W. Rucks, IV
WILLIAM W. RUCKS, IV

Director

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets of PetroQuest Energy, Inc.

Consolidated Statements of Operations of PetroQuest Energy, Inc.

Consolidated Statements of Comprehensive Income (Loss) of PetroQuest
Energy, Inc.

Consolidated Statements of Cash Flows of PetroQuest Energy, Inc.

Consolidated Statements of Stockholders’ Equity of PetroQuest Energy,
Inc.

Notes to Consolidated Financial Statements

F-1

F-2

F-3

F-4

F-5

F-6

F-7

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
PetroQuest Energy, Inc.

We have audited the accompanying consolidated balance sheets of PetroQuest Energy, Inc. as of December 31, 2015 and 2014,
and the related consolidated statements of operations, comprehensive income (loss), cash flows and stockholders’ equity for each
of the three years in the period ended December 31, 2015. 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 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, the financial statements referred to above present fairly, in all material respects, the consolidated financial position
of PetroQuest Energy, Inc. at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for
each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
PetroQuest Energy, Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013
framework) and our report dated March 4, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana
March 4, 2016

F-1

PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)

ASSETS

Current assets:

Cash and cash equivalents
Revenue receivable
Joint interest billing receivable
Derivative asset
Other current assets

Total current assets
Property and equipment:

Oil and gas properties:

Oil and gas properties, full cost method
Unevaluated oil and gas properties
Accumulated depreciation, depletion and amortization

Oil and gas properties, net

Other property and equipment
Accumulated depreciation of other property and equipment

Total property and equipment
Other assets, net of accumulated amortization of $3,842 and $3,448, respectively
Total assets

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts payable to vendors
Advances from co-owners
Oil and gas revenue payable
Accrued interest and preferred stock dividend
Asset retirement obligation
Accrued acquisition costs
Other accrued liabilities

Total current liabilities
Bank debt
10% Senior Notes
Asset retirement obligation
Other long-term liability
Commitments and contingencies
Stockholders’ equity:

Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495
shares
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 65,641
and 64,721 shares, respectively
Paid-in capital
Accumulated other comprehensive income
Accumulated deficit

Total stockholders’ equity
Total liabilities and stockholders’ equity

See accompanying Notes to Consolidated Financial Statements.

F-2

December 31,
2015

December 31,
2014

148,013
6,476
49,374
1,508
3,874
209,245

1,310,891
12,516
(1,157,455)
165,952
11,229
(8,737)
168,444
1,630
379,319

97,999
16,118
18,911
12,795
6,015
4,409
2,537
158,784
—
347,008
36,541
53

18,243
16,485
46,778
8,631
6,413
96,550

2,222,753
109,119
(1,648,060)
683,812
14,953
(10,313)
688,452
1,106
786,108

102,954
12,819
22,333
12,764
2,756
17,690
5,394
176,710
75,000
345,213
52,214
62

66
290,382
947
(454,463)
(163,067)
379,319

65
285,957
5,420
(154,534)
136,909
786,108

PETROQUEST ENERGY, INC.
Consolidated Statements of Operations
(Amounts in Thousands, Except Per Share Data)

Revenues:

Oil and gas sales

Expenses:

Lease operating expenses
Production taxes
Depreciation, depletion and amortization
Ceiling test write-down
General and administrative
Accretion of asset retirement obligation
Interest expense

Other income:

Gain on sale of assets
Other income
Derivative income

Income (loss) from operations

Income tax expense (benefit)

Net income (loss)
Preferred stock dividend
Net income (loss) available to common stockholders
Earnings per common share:

Basic

Net income (loss) per share

Diluted

Net income (loss) per share
Weighted average number of common shares:

Basic
Diluted

Year Ended
December 31,

2015

2014

2013

115,969

225,021

182,804

40,130
2,470
63,497
266,562
20,777
3,259
33,766
430,461

21,937
391
—
22,328
(292,164)
2,626
(294,790)
5,139

$ (299,929) $

48,597
5,927
87,818
—
22,870
2,958
29,281
197,451

—
679
—
679
28,249
(2,941)
31,190
5,139
26,051

(4.61) $

0.39

(4.61) $

0.39

43,743
3,950
71,445
—
26,512
1,753
21,886
169,289

—
654
233
887
14,402
320
14,082
5,139
8,943

0.14

65,022
65,022

64,204
64,225

63,054
63,208

See accompanying Notes to Consolidated Financial Statements.

F-3

PETROQUEST ENERGY, INC.
Consolidated Statements of Comprehensive Income (Loss)
(Amounts in Thousands)

Net income (loss)

Change in fair value of derivatives, net of income tax (expense)
benefit of $2,650, ($3,211) and $309 respectively

Comprehensive income (loss)

Year Ended

December 31,

2015

$ (294,790) $

(4,473)

$ (299,263) $

2014
31,190

6,516
37,706

2013
14,082

(1,617)
12,465

See accompanying Notes to Consolidated Financial Statements.

F-4

PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(Amounts in Thousands)

Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:

Deferred tax expense (benefit)
Depreciation, depletion and amortization
Ceiling test write-down
Accretion of asset retirement obligation
Share based compensation expense

Gain on sale of assets

Amortization costs and other
Non-cash derivative income

Payments to settle asset retirement obligations
Changes in working capital accounts:

Revenue receivable
Prepaid drilling and pipe costs
Joint interest billing receivable
Accounts payable and accrued liabilities
Advances from co-owners
Other

Net cash provided by operating activities
Cash flows provided by (used in) investing activities:

Investment in oil and gas properties
Investment in other property and equipment

Sale of oil and gas properties

Net cash provided by (used in) investing activities
Cash flows provided by (used in) financing activities:
Net payments for share based compensation
Deferred financing costs
Payment of preferred stock dividend
Proceeds from bank borrowings
Repayment of bank borrowings
Proceeds from issuance of 10% Senior Notes
Costs to issue 10% Senior Notes

Net cash provided by (used in) financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Supplemental disclosure of cash flow information:

Cash paid during the period for:

Interest
Income taxes

Year Ended

December 31,

2015

2014

2013

$ (294,790) $

31,190

14,082

2,626
63,497
266,562
3,259
4,617
(21,937)
2,259
—
(2,776)

10,009
—
223
(9,400)
3,299
2,657
30,105

(2,941)
87,818
—
2,958
5,248
—
2,188
—
(3,623)

10,083
(370)
(20,276)
50,243
11,850
3,840
178,208

320
71,445
—
1,753
4,216
—
1,473
(233)
(3,335)

(8,826)
1,221
15,685
(12,865)
(19,490)
(5,592)
59,854

(90,218)
(454)
271,769
181,097

(174,633)
(926)
11,908
(163,651)

(298,824)
(1,679)
20,400
(280,103)

(199)
(1,094)
(5,139)
70,000
(145,000)
—
—
(81,432)
129,770
18,243
$ 148,013

(75)
(253)
(5,139)
17,500
(17,500)
—
—
(5,467)
9,090
9,153
18,243

$
$

36,217

$
— $

37,174
270

(38)
(320)
(5,139)
73,000
(48,000)
200,000
(5,005)
214,498
(5,751)
14,904
9,153

20,101
12

$
$

See accompanying Notes to Consolidated Financial Statements.

F-5

PetroQuest Energy Inc.
Consolidated Statements of Stockholders’ Equity
(Amounts in Thousands)

Common
Stock

Preferred
Stock

Paid-In
Capital

Other
Comprehensive
Income (Loss)

Accumulated
Deficit

Total
Stockholders’
Equity

December 31, 2012

Options exercised

Retirement of shares upon
vesting of restricted stock

Share-based compensation
expense

Issuance of shares under
employee stock purchase plan

Derivative fair value
adjustment, net of tax

Preferred stock dividend

Net income

December 31, 2013

Options exercised
Retirement of shares upon
vesting of restricted stock

Share-based compensation
expense

Issuance of shares under
employee stock purchase plan

Derivative fair value
adjustment, net of tax

Preferred stock dividend

Net income

December 31, 2014

Options exercised

Retirement of shares upon
vesting of restricted stock

Share-based compensation
expense

Issuance of shares under
employee stock purchase plan

Derivative fair value
adjustment, net of tax
Preferred stock dividend

Net loss

December 31, 2015

—

$ 276,534

521

$ (189,528) $

87,591

731

(1,057)

4,216

287

—

(1,617)
—

—

—
(5,139)
14,082

731

(1,056)

4,216

287

(1,617)
(5,139)
14,082

$ 280,711

(1,096) $ (180,585) $

99,095

1,032

(1,310)

5,248

276

—

6,516

—

$ 285,957

5,420

—

—
(5,139)
31,190
$ (154,534) $

(452)

4,617

199

—

$ 290,382

—

(4,473)
—

—

947

—
(5,139)
(294,790)

(4,473)
(5,139)
(294,790)
$ (454,463) $ (163,067)

1,032

(1,309)

5,248

276

6,516
(5,139)
31,190

136,909

(451)

4,617

199

See accompanying Notes to Consolidated Financial Statements.

F-6

PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Summary of Significant Accounting Policies

PetroQuest Energy, Inc. (a Delaware Corporation) (“PetroQuest”) is an independent oil and gas company headquartered
in Lafayette, Louisiana with exploration offices in The Woodlands, Texas and Tulsa, Oklahoma. It is engaged in the exploration,
development, acquisition and operation of oil and gas properties in Texas and the Gulf Coast Basin, as well as in Oklahoma.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of PetroQuest and its subsidiaries, PetroQuest Energy, L.L.C.,
PetroQuest Oil & Gas, L.L.C, Pittrans, Inc. and TDC Energy LLC (collectively, the "Company"). All intercompany accounts and
transactions have been eliminated. Certain prior period amounts have been reclassified to conform to current year presentation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States
requires management to make estimates and assumptions that affect the 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. Actual results could differ from those estimates.

Oil and Gas Properties

The Company utilizes the full cost method of accounting, which involves capitalizing all acquisition, exploration and
development costs incurred for the purpose of finding oil and gas reserves including the costs of drilling and equipping productive
wells, dry hole costs, lease acquisition costs and delay rentals. The Company also capitalizes the portion of general and
administrative costs that can be directly identified with acquisition, exploration or development of oil and gas properties.
Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the
properties are sold, or management determines these costs to have been impaired. Interest is capitalized on unevaluated property
costs. Transactions involving sales of reserves in place are recorded as adjustments to accumulated depreciation, depletion and
amortization with no gain or loss recognized, unless such adjustments would cause a significant alteration in the relationship
between capitalized costs and proved reserves.

Depreciation, depletion and amortization of oil and gas properties is computed using the unit-of-production method based
on estimated proved reserves. All costs associated with evaluated oil and gas properties, including an estimate of future development
costs associated therewith, are included in the depreciable base. The costs of investments in unevaluated properties are excluded
from this calculation until the related properties are evaluated, proved reserves are established or the properties are determined to
be impaired. Proved oil and gas reserves are estimated annually by independent petroleum engineers.

The capitalized costs of proved oil and gas properties cannot exceed the present value of the estimated net future cash
flows from proved reserves based on historical first of the month average twelve-month oil, gas and natural gas liquid prices,
including the effect of hedges in place (the full cost ceiling). If the capitalized costs of proved oil and gas properties exceed the
full cost ceiling, the Company is required to write-down the value of its oil and gas properties to the full cost ceiling amount. The
Company follows the provisions of Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of ASC Topic 410-20
by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and
abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation.
The estimated future cash outflows associated with settling the recorded asset retirement obligations are excluded from the
computation of the present value of estimated future net revenues used in applying the ceiling test.

Cash and Cash Equivalents

The Company considers all highly liquid investments with a stated maturity of three months or less to be cash and cash
equivalents. The majority of the Company’s cash and cash equivalents are in overnight securities made through its commercial
bank accounts, which result in available funds the next business day.

Accounts Receivable

In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their

respective working interests.

F-7

Other Property and Equipment

The costs related to other furniture and fixtures are depreciated on a straight line basis over estimated useful lives ranging
from three to eight years. During 2012, a field office servicing the Company's Oklahoma assets was built and is being depreciated
over 39 years.

Other Assets

Other assets at December 31, 2015 and 2014 included $1.4 million and $0.7 million, respectively, related to deferred
financing costs with respect to the Company's bank credit facility, which are amortized on a straight-line basis over the life of the
facility.

Income Taxes

The Company accounts for income taxes in accordance with ASC Topic 740. Provisions for income taxes include deferred
taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial
reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are
capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment
and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most
other exploratory and development costs are charged to expense as incurred; however, the Company may use certain provisions
of the Internal Revenue Code which allow capitalization of intangible drilling costs. Other financial and income tax reporting
differences occur primarily as a result of statutory depletion. Deferred tax assets are assessed for realizabilty and a valuation
allowance is established for any portion of the asset for which it is more likely than not will not be realized.

Revenue Recognition

The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the
Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts
to which the Company is entitled based on its interest in the properties.

Concentrations

The Company’s production is sold on month to month contracts at prevailing prices. The Company attempts to diversify
its sales among multiple purchasers and obtain credit protection such as letters of credit and parental guarantees when necessary.

The following table identifies customers from whom the Company derived 10% or more of its oil and gas revenues during
the years presented. Based on the availability of other customers, the Company does not believe the loss of any of these customers
would have a significant effect on its business or financial condition.

Laclede Energy
Shell Trading Co.
Unimark, LLC
BG Group

(a) Less than 10 percent

Derivative Instruments

Year Ended December 31,

2015
21%
18%
17%
10%

2014
24%
30%
14%
(a)

2013
14%
35%
14%
(a)

Under ASC Topic 815, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge
accounting treatment. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair
value and subsequent changes in fair value are recognized in stockholders’ equity through other comprehensive income (loss), net
of related taxes, to the extent the hedge is effective. If a hedge becomes ineffective because the hedged production does not occur,
or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded
in the statement of operations as derivative income (expense). The Company does not offset fair value amounts recognized for
derivative instruments. The cash settlements of hedges are recorded as adjustments to oil and gas sales. Oil and gas revenues
include additions (reductions) related to the net settlement of hedges totaling $17.1 million, ($3.0) million and $0.9 million during
2015, 2014 and 2013, respectively.

The Company’s hedges are specifically referenced to NYMEX prices for oil and natural gas. The effectiveness of hedges
is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the
correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the
F-8

Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX
prices at which the hedges will be settled. At December 31, 2015, the Company’s derivative instruments were designated as
effective cash flow hedges. See Note 8 for further discussion of the Company’s derivative instruments.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)
2014-09, “Revenue from Contracts with Customers” to clarify the principles for recognizing revenue and to develop a common
revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when
it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled
in exchange for those goods and or services. In August 2015, the FASB issued ASU 2015-14 deferring the effective date of ASU
2014-09 by one year to interim and annual periods beginning on or after December 31, 2017. Early application is not permitted.
Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the
cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. The Company is currently
evaluating the effect that this new standard will have on its consolidated financial statements and related disclosures, however,
the Company does not expect the adoption of the standard will have a material impact on its consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs", which changes
the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related debt
liability rather than as an asset. Additionally, in August 2015, the FASB issued ASU No. 2015-15, "Presentation and Subsequent
Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which was issued to clarify the guidance
with respect to the presentation of debt issuance costs related to line-of-credit arrangements. ASU 2015-15 clarifies that the SEC
staff would not object to an entity deferring and presenting such debt issuance costs as an asset and subsequently amortizing the
deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding
borrowings on the line-of-credit arrangement. The Company has elected to early adopt this standard effective December 31, 2015.
As a result, deferred financing costs, net of accumulated amortization, related to the Company's 10% Senior Notes due 2017 of
$3.0 million and $4.8 million as of December 31, 2015 and 2014, respectively, were reclassified from other assets to a direct
reduction from the carrying amount of the related debt.

Note 2—Acquisitions and Divestitures

Acquisitions:

Gulf of Mexico

On July 3, 2013, the Company acquired certain shallow water Gulf of Mexico shelf oil and gas properties (the “Acquired
Assets”), for an aggregate cash purchase price of $188.8 million, reflecting an effective date of January 1, 2013 (collectively, the
"Gulf of Mexico Acquisition"). The Acquired Assets included 16 gross wells located on seven platforms.

The aggregate cash purchase price of the Gulf of Mexico Acquisition was financed with the net proceeds from the sale
of $200 million in aggregate principal amount of the Company's 10% Senior Notes due 2017. In connection with the transaction,
the Company recorded $5 million of deferred financing costs and incurred $4.0 million of acquisition-related costs, including $2.6
million related to a bridge commitment fee, which were recognized as general and administrative expenses during 2013.

The Gulf of Mexico Acquisition was accounted for under the acquisition method of accounting, which involves
determining the fair value of the assets acquired and liabilities assumed. The fair value of proved and unevaluated oil and gas
properties was estimated using the income approach based on estimated reserve quantities, costs to produce and develop reserves,
and forward prices for oil and gas, which represent Level 2 and Level 3 inputs. Asset retirement obligations were determined in
accordance with applicable accounting standards.

The following table summarizes the acquisition date fair values of the net assets acquired (in thousands):

Oil and gas properties

Unevaluated oil and gas properties

Asset retirement obligations

Net assets acquired

192,067

12,033
(15,319)
188,781

The following unaudited summary pro forma financial information for the twelve month periods ended December 31,
2013 has been prepared to give effect to the Gulf of Mexico Acquisition as if it had occurred on January 1, 2012. The pro forma
financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January
1, 2012 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in
the following unaudited pro forma financial information because of normal production declines, changes in commodity prices,

F-9

future acquisitions and divestitures, future development and exploration activities and other factors. Amounts are presented in
thousands, except per share amounts.

Revenues

Income from Operations

Net Income available to common stockholders

Basic Earnings per Share

Diluted Earnings per Share

Twelve Months Ended
December 31, 2013

215,666

19,858

14,399

0.22

Fleetwood Joint Venture

The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion
and lease acquisition costs. At December 31, 2015, $4.4 million of this drilling carry remained outstanding. The liability is reflected
as accrued acquisition costs in the Consolidated Balance Sheet. During February 2016, the Company paid $4.4 million to settle
this liability with its joint venture partner in connection with the terms of the agreement.

Divestiture:

On June 4, 2015, the Company completed the sale of a majority of its interests in the Woodford and Mississippian Lime
(the “Oklahoma Divestiture”) for $280 million, subject to customary post-closing purchase price adjustments, effective January 1,
2015. At closing, the Company received $257.7 million in cash and recognized a receivable of $13.9 million, which was received
in full during the third quarter of 2015.

In connection with the sale, the Company entered into a Contract Operating Services Agreement ("COSA") whereby the
Company will retain a minimal working interest in the Sold Assets and will provide certain services as a contract operator for a
period of one year from the closing date of the sale, subject to renewal for two additional one-year terms.

At December 31, 2014, the estimated proved reserves attributable to the Oklahoma Divestiture totaled approximately 227.2
Bcfe (unaudited), which represented approximately 57% (unaudited) of the Company's estimated proved reserves. Under the full
cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or
loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. A
significant alteration is generally not expected to occur for sales involving less than 25% of the total proved reserves. If the
divestiture of the Oklahoma Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized,
the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the
Company recognized a gain on the sale of $23.2 million during 2015. The carrying value of the properties sold was determined
by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative
fair values.

Note 3—Subsequent Event

On January 14, 2016 the Company announced the commencement of a private exchange offer (the "Exchange Offer")
and consent solicitation (the "Consent Solicitation") to certain eligible holders for up to $300 million aggregate principal amount
of its outstanding 10% Senior Notes due 2017 (the "Old Notes") for up to (i) $75 million in cash, (ii) $202.5 million aggregate
principal amount of its newly issued 10% Second Lien Senior Secured Notes due 2021 (the "New Notes"), and (iii) 6 million
shares of its common stock. The Exchange Offer and Consent Solicitation were made upon the terms and subject to the conditions
set forth in the Confidential Offering Memorandum and Consent Solicitation Statement (the "Offering Memorandum") and related
letter of transmittal and consent, each dated January 14, 2016.

The Exchange Offer and Consent Solicitation closed on February 17, 2016, and in satisfaction of the consideration for
$214.4 million in aggregate principal amount of the Old Notes, representing approximately 61% of the outstanding aggregate
principal amount of Old Notes, validly tendered (and not validly withdrawn) in the Exchange Offer, the Company (i) paid
approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of New Notes and (iii) issued 4,287,580
shares of its common stock. Following the completion of the Exchange Offer, $135.6 million in aggregate principal amount of

F-10

the Old Notes remain outstanding. The Consent Solicitation eliminates or waives substantially all of the restrictive covenants
contained in the indenture governing the Old Notes.

The indenture governing the New Notes contains affirmative and negative covenants that, among other things, limit the
ability of the Company and the subsidiary guarantors of the New Notes to incur indebtedness; purchase or redeem stock; make
certain investments; create liens that secure debt; enter into transactions with affiliates; sell assets; refinance certain indebtedness;
merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or
make other distributions on stock. The New Notes are fully and unconditionally guaranteed on a senior basis by certain wholly-
owned subsidiaries of the Company.

The Company will pay 10% interest per annum on the principal amount of the New Notes, semi-annually in arrears on

February 15 and August 15 of each year.

The New Notes are secured by second-priority liens on substantially all of the Company’s and the subsidiary guarantors’
oil and gas properties and substantially all of their other assets to the extent such properties and assets secure the Credit Agreement
(as defined below), except for certain excluded assets. Pursuant to the terms of an intercreditor agreement, the security interest
in those properties and assets that secure the New Notes and the guarantees are contractually subordinated to liens that secure the
Credit Agreement and certain other permitted indebtedness. Consequently, the New Notes and the guarantees will be effectively
subordinated to the Credit Agreement and such other indebtedness to the extent of the value of such assets.

Note 4—Convertible Preferred Stock

The Company has 1,495,000 shares of 6.875% Series B Cumulative Convertible Perpetual Preferred Stock (the “Series

B Preferred Stock”) outstanding.

The following is a summary of certain terms of the Series B Preferred Stock:

Dividends. The Series B Preferred Stock accumulates dividends at an annual rate of 6.875% for each share of Series B
Preferred Stock. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited
by the Company’s debt agreements, assets are legally available to pay dividends and the Company’s board of directors or an
authorized committee of the board declares a dividend payable, the Company pays dividends in cash, every quarter.

On January 26, 2016, in connection with an amendment to the Company's bank credit facility prohibiting the Company
from declaring or paying dividends on the Series B Preferred Stock, the Company announced its intention to suspend the quarterly
cash dividend on it Series B Preferred Stock beginning with the dividend payment due on April 15, 2016. Under the terms of the
Series B Preferred Stock, any unpaid dividends will accumulate. If the Company fails to pay six quarterly dividends on the Series
B Preferred Stock, whether or not consecutive, holders of the Series B Preferred Stock, voting as a single class, will have the right
to elect two additional directors to the Company's Board of Directors until all accumulated and unpaid dividends on the Series B
Preferred Stock are paid in full.

Mandatory conversion. The Company may, at its option, cause shares of the Series B Preferred Stock to be automatically
converted at the applicable conversion rate, but only if the closing sale price of the Company’s common stock for 20 trading days
within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the
conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.

Conversion rights. Each share of Series B Preferred Stock may be converted at any time, at the option of the holder, into
3.4433 shares of the Company’s common stock (which is based on an initial conversion price of approximately $14.52 per share
of common stock, subject to adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a
portion of any such conversion in cash or shares of the Company’s common stock. If the Company elects to settle all or any portion
of its conversion obligation in cash, the conversion value and the number of shares of the Company’s common stock it will deliver
upon conversion (if any) will be based upon a 20 trading day averaging period.

Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on
the Series B Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50 divided
by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The
conversion price on the conversion date and the number of shares of the Company’s common stock, as applicable, to be delivered
upon conversion may be adjusted if certain events occur.

F-11

Note 5—Earnings Per Share

A reconciliation between the basic and diluted earnings per share computations (in thousands, except per share

amounts) is as follows:

For the Year Ended December 31, 2015

Loss(Numerator)

Shares
(Denominator)

Per
Share Amount

BASIC EPS

Net loss available to common stockholders

Stock options

Attributable to participating securities

DILUTED EPS

For the Year Ended December 31, 2014

Net income available to common stockholders

Attributable to participating securities

BASIC EPS

Net income available to common stockholders

Effect of dilutive securities:

Stock options

Attributable to participating securities

DILUTED EPS

For the Year Ended December 31, 2013

Net income available to common stockholders

Attributable to participating securities

BASIC EPS

Net income available to common stockholders

Effect of dilutive securities:

Stock options

Attributable to participating securities

DILUTED EPS

(299,929)
—

—
(299,929)

65,022

(4.61)

—

65,022

(4.61)

Income
(Numerator)

Shares
(Denominator)

Per
Share Amount

26,051
(855)
25,196

26,051

—
(854)
25,197

0.39

64,204

—

64,204

—

64,225

0.39

Income
(Numerator)

Shares
(Denominator)

Per
Share Amount

8,943
(257)
8,686

8,943

—
(256)
8,687

0.14

63,054

—

63,054

154

—

63,208

0.14

An aggregate of 0.3 million shares of common stock representing options to purchase common stock and unvested shares
of restricted common stock and common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling
5.1 million shares were not included in the computation of diluted earnings per share for the year ended December 31, 2015,
because the inclusion would have been anti-dilutive as a result of the net loss reported for the year.

Common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 5.1 million shares during

2014 and 2013 were not included in the computation of diluted earnings per share because the inclusion would have been anti-
dilutive. Options to purchase 1.0 million and 1.2 million shares of common stock were outstanding during the year ended
December 31, 2014 and 2013, respectively, and were not included in the computation of diluted earnings per share because the
options' exercise prices were in excess of the average market price of the common shares.

F-12

Note 6—Share-Based Compensation

The Company accounts for share-based compensation in accordance with ASC Topic 718. Share-based compensation
cost is recognized over the requisite service period. Compensation cost for awards with graded vesting is recognized using the
accelerated attribution method. Share-based compensation cost is reflected as a component of general and administrative expenses.
A detail of share-based compensation cost for the years ended December 31, 2015, 2014 and 2013 is as follows (in thousands):

Year Ended December 31,
2014

2013

2015

Stock options:

Incentive Stock Options (share settled)
Non-Qualified Stock Options (share settled)

Restricted stock (share settled)
Cash settled stock units
Share-based compensation

243
71
4,303
(439)
4,178

573
171
4,504
3,094
8,342

310
222
3,684
1,611
5,827

During the years ended December 31, 2014 and 2013, the Company capitalized $1.5 million and $0.8 million of
compensation cost related to cash settled restricted stock units to oil and gas properties. No such amounts were capitalized during
the year ended December 31, 2015. During the years ended December 31, 2015, 2014 and 2013, the Company recorded income
tax benefits of approximately $1.5 million, $2.3 million and $1.8 million, respectively, related to share-based compensation expense
recognized during those periods. Any excess tax benefits from the vesting of restricted stock and the exercise of stock options
will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, all of the Company’s
income taxes are deferred and the Company has net operating losses available to carryover to future periods. Accordingly, no
excess tax benefits have been recognized for any periods presented.

Share-Based Compensation settled in stock

At December 31, 2015, the Company had $2.3 million of unrecognized compensation cost related to unvested restricted
stock and stock options. This amount will be recognized as compensation expense over a weighted average period of approximately
two years.

Stock Options

Stock options generally vest equally over a three-year period, must be exercised within 10 years of the grant date and
may be granted only to employees, directors and consultants. The exercise price of each option may not be less than 100% of the
fair market value of a share of common stock on the date of grant. Upon a change in control of the Company, all outstanding
options become immediately exercisable.

The Company computes the fair value of its stock options using the Black-Scholes option-pricing model assuming a
stock option forfeiture rate and expected term based on historical activity and expected volatility computed using historical stock
price fluctuations on a weekly basis for a period of time equal to the expected term of the option. Periodically, the Company adjusts
compensation expense based on the difference between actual and estimated forfeitures.

F-13

There were no stock options granted in 2015. The following table outlines the assumptions used in computing the fair

value of stock options granted during 2014 and 2013:

Dividend yield
Expected volatility
Risk-free rate

Expected term
Forfeiture rate
Stock options granted (1)
Wgtd. avg. grant date fair value per share
Fair value of grants (1)

Years Ended December 31,

2014
—%
79.4% - 80.0%
1.81% - 2.015%
6 years
5.0%
69,434
$2.84
$197,000

2013
—%
79.6% - 79.8%
0.9% - 1.815%
6 years
5.0%
395,642
$2.91
$1,150,000

(1) Prior to applying estimated forfeiture rate

The following table details stock option activity during the year ended December 31, 2015:

Outstanding at beginning of year
Granted
Expired/cancelled/forfeited
Exercised
Outstanding at end of year

Number of
Options
1,517,704
—
(155,680)
—
1,362,024

Wgtd. Avg.
Exercise Price
6.05
$
—
5.70
—
6.09

Wgtd. Avg.
Remaining
Life

Aggregate
Intrinsic Value
(000’s)

5.6 years

$
$

—

—
—

Options exercisable at end of year
Options expected to vest

1,217,486
137,311

6.33
4.13

4.4 years
7.9 years

The total fair value of stock options that vested during the years ended December 31, 2015, 2014 and 2013 was $0.8
million, $1.0 million and $0.8 million, respectively. The intrinsic value of stock options exercised was immaterial for all periods
presented.

The following table summarizes information regarding stock options outstanding at December 31, 2015:

Range of

Exercise

Price
$2.24—$4.48
$4.49—$6.72
$6.73—$8.96
$8.97—$11.20

Restricted Stock

Options

Outstanding

12/31/2015

386,908
220,487
744,629
10,000
1,362,024

Wgtd. Avg.

Remaining

Contractual Life
7.8 years
5.7 years
4.5 years
0.1 years
5.6 years

Wgtd. Avg.

Exercise

Price

$4.13
$5.46
$7.25
$9.99
$6.09

Options

Exercisable

12/31/2015

251,701
211,156
744,629
10,000
1,217,486

Wgtd. Avg.

Exercise

Price

$4.16
$5.48
$7.25
$9.99
$6.33

The Company computes the fair value of its service based restricted stock using the closing price of the Company’s stock
at the date of grant, and compensation expense is recognized assuming a 5% estimated forfeiture rate. Restricted stock granted to
employees prior to 2011 generally vests over a five-year period with one-fourth vesting on each of the first, second, third and fifth
anniversaries of the date of the grant. No portion of the restricted stock vests on the fourth anniversary of the date of the grant.
Beginning in 2011, restricted stock granted to employees generally vests evenly over a three year period. Prior to 2013, restricted
stock granted to directors generally vested evenly over a three-year period. Beginning in 2013, restricted stock granted to directors
vests one year from the date of grant, to align with their term on the board. Upon a change in control of the Company, all outstanding
shares of restricted stock will become immediately vested.

F-14

The following table details restricted stock activity during the year ended December 31, 2015:

Number of
Shares

Wgtd. Avg.
Fair Value per
Share

Outstanding at beginning of year
Granted
Cancelled/forfeited
Lapse of restrictions
Outstanding at December 31, 2015

2,428,202
54,717
(187,730)
(1,110,013)
1,185,176

4.37
1.27
3.88
4.27
3.81

The weighted average grant date fair value of restricted stock granted during the years ended December 31, 2015, 2014
and 2013 was $1.27, $4.32 and $4.18, respectively, per share. The total fair value of restricted stock that vested during the years
ended December 31, 2015, 2014 and 2013 was $4.7 million, $5.0 million and $5.4 million, respectively. At December 31, 2015,
the weighted average remaining life of restricted stock outstanding was approximately three years and the intrinsic value of
restricted stock outstanding, using the closing stock price on December 31, 2015, was $0.6 million.

Share-Based Compensation settled in cash

Restricted Stock Units

The Company grants restricted stock units ("RSUs") to employees that vest evenly over a three-year period. Cash payment
will be made to employees on each vesting date based upon the Company's closing stock price on that date. Upon change in
control of the Company, all of the RSUs will immediately vest. The Company computes the fair value of the RSUs using the
closing price of the Company's stock at the end of each period and records a liability based on the percentage of requisite service
rendered at the reporting date. During 2015, the Company paid $0.7 million for 0.7 million units that vested during the period.

Market Based Restricted Stock Units

The Company granted 243,067 market based restricted stock units ("MRSUs") to executive officers during November
2014. The executive officers can earn between 0-200%of the MRSUs granted based on the Company's performance versus a
defined peer group. The MRSUs vest in one-third increments on each of the first, second and third annual anniversaries starting
January 1, 2016. Upon change in control of the Company, all of the MRSUs will immediately vest. The number of MRSUs that
ultimately vest is based on the Company's total shareholder return in the last 20 days of the fiscal year in relation to the last 20
days of the previous fiscal year in comparison to a group of 12 selected peer stocks of similar sized companies which operate
within the same sector. The performance period ended on December 31, 2015 and executive officers earned 50% of the MRSUs.
The MRSUs are cash settled on each vesting date based on the number of MRSUs that vest multiplied by the Company's closing
stock price. The Company estimates the fair value of the outstanding MRSUs using a Monte Carlo valuation model and records
a liability based on the percentage of requisite service rendered at the reporting date. The Monte Carlo valuation model considers
such inputs as the Company's and its peer group's stock prices, a risk-free interest rate, and an estimated volatility for the Company
and its peer group. As of December 31, 2015, the Company had a liability for RSUs and MRSUs outstanding in the amount of
$0.2 million based upon the closing stock price at December 31, 2015.

The following table details MRSU and RSU activity during the year ended December 31, 2015:

Outstanding at beginning of year

Granted

Expired/Cancelled/Forfeited

Vested/Paid

Outstanding at December 31, 2015

Note 7—Asset Retirement Obligation

MRSU

RSU

Total

243,067

—
(139,784)
—

103,283

1,379,261

1,622,328

182,505
(120,438)
(687,704)
753,624

182,505
(260,222)
(687,704)
856,907

The Company accounts for asset retirement obligations in accordance with ASC Topic 410-20, which requires recording
the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred. Asset retirement
obligations associated with long-lived assets included within the scope of ASC Topic 410-20 are those for which there is a legal
obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of

F-15

promissory estoppel. The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has
acquired and constructed.

The following table describes the changes to the Company’s asset retirement obligation (in thousands):

Asset retirement obligation, beginning of period
Liabilities incurred
Liabilities settled
Accretion expense
Revisions in estimated cash flows
Asset retirement obligation, end of period
Less: current portion of asset retirement obligation
Long-term asset retirement obligation

Year Ended December 31,

2015

2014

54,970
466
(5,002)
3,259
(11,137)
42,556
(6,015)
36,541

48,536
756
(3,623)
2,958
6,343
54,970
(2,756)
52,214

Liabilities settled during 2015 included $1.8 million as a result of the sale of our Woodford and Mississippian Lime assets.

Note 8—Derivative Instruments

The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through
commodity derivative instruments. When the conditions for hedge accounting are met, the Company may designate its commodity
derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment
are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a derivative does
not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the statement of operations
as derivative income (expense). At December 31, 2015 and 2014, all of the Company's outstanding derivative instruments were
designated as cash flow hedges.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $15,940,000, ($4,237,000) and
$1,098,000, Ngl hedges of $530,000, $296,000 and $61,000, and oil hedges of $644,000, $897,000 and ($232,000), for the years
ended December 31, 2015, 2014 and 2013, respectively.

As of December 31, 2015, the Company had entered into the following gas hedge contract:

Production Period
Natural Gas:
January 2016 - June 2016

Instrument
Type

Daily Volumes

Weighted Average
Price

Swap

10,000 Mmbtu

$3.22

At December 31, 2015, the Company had recognized an asset of approximately $1.5 million related to the estimated fair
value of this derivative contract. Based on estimated future commodity prices as of December 31, 2015, the Company would
realize a $0.9 million gain, net of taxes, during the next 12 months. This gain is expected to be reclassified to oil and gas sales
based on the schedule of volumes stipulated in the derivative contracts.

During January 2016, the Company entered into the following additional derivative contract accounted for as a cash flow

hedge:

Production Period

Natural Gas:

Instrument
Type

Daily Volumes

Weighted
Average Price

July 2016 - December 2016

Swap

5,000 Mmbtu

$2.50

F-16

Derivatives designated as hedging instruments:

The following tables reflect the fair value of the Company’s effective cash flow hedges in the consolidated financial

statements (in thousands):

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at December 31, 2015 and December 31, 2014:

Period
December 31, 2015
December 31, 2014

Commodity Derivatives

Balance Sheet
Location

Fair Value

Derivative asset
Derivative asset

$
$

1,508
8,631

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for years ended December 31, 2015, 2014 and 2013:

Instrument
Commodity Derivatives at December 31, 2015
Commodity Derivatives at December 31, 2014
Commodity Derivatives at December 31, 2013

Derivatives not designated as hedging instruments:

Amount of Gain (Loss)
Recognized in Other
Comprehensive Income
9,991
$
6,683
$
(999)
$

Location of
Gain Reclassified
into Income
Oil and gas sales
Oil and gas sales
Oil and gas sales

Amount of Gain (Loss)
Reclassified into
Income

$
$
$

17,114
(3,044)
927

The Company’s three-way collar contract for 2013 gas production was not designated as an effective cash flow hedge
and therefore the gain on this contract was recorded as derivative income in the statement of operations. The following table
reflects the effect of this contract in the consolidated statements of operations (in thousands):

Effect of Non-designated Derivative Instrument on the Consolidated Statement of Operations for the year ended December 31,
2013:

Instrument
Commodity Derivatives at December 31, 2013

Amount of Gain
Recognized in Derivative
Income

233

F-17

Note 9 - Fair Value Measurements

ASC Topic 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date and establishes a fair value hierarchy that prioritizes the
inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad
levels:

• Level 1: valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the

highest priority;

• Level 2: valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset

or liability;

• Level 3: valuations are based on prices or third party or internal valuation models that require inputs that are significant

to the fair value measurement and are less observable and thus have the lowest priority.

The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company's
derivative instruments at December 31, 2015 and 2014 were in the form of swaps based on NYMEX pricing for natural gas. The
fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated
inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an
estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative
liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.

The following table summarizes the Company’s assets (liabilities) that are subject to fair value measurement on a recurring basis
as of December 31, 2015 and December 31, 2014 (in thousands):

Instrument
Commodity Derivatives:

At December 31, 2015
At December 31, 2014

Fair Value Measurements Using

Quoted Prices
in Active
Markets (Level 1)

Significant Other
Observable
Inputs (Level 2)

Significant
Unobservable
Inputs (Level 3)

$
$

— $
— $

1,508
8,631

$
$

—
—

The fair value of the Company's cash and cash equivalents and variable-rate bank debt approximated book value at
December 31, 2015 and 2014. The fair value of the Company's $350 million of 10% Senior Notes due 2017 (the "Notes") was
approximately $238 million and $301 million as of December 31, 2015 and 2014, respectively. The fair value of the Notes was
determined based upon a market quote provided by an independent broker, which represents a Level 2 input.

Note 10—Long-Term Debt

On August 19, 2010, the Company issued $150 million in principal amount of the Notes and on July 3, 2013, the Company
issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (collectively, the "Notes"). The Notes
are guaranteed by certain of PetroQuest's subsidiaries. The subsidiary guarantors are 100% owned by PetroQuest and all guarantees
are full and unconditional and joint and several. PetroQuest has no independent assets or operations and the subsidiaries not
providing guarantees are minor, as defined by the rules of the Securities and Exchange Commission.

Interest is payable semi-annually on March 1 and September 1. At December 31, 2015, $11.7 million had been accrued
in connection with the March 1, 2016 interest payment (which amount was reduced to $4.5 million as a result of the Exchange
Offering) and the Company was in compliance with all of the covenants contained in the Notes.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit
Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A.
and The Bank of Nova Scotia. The Credit Agreement provides the Company with a $300 million revolving credit facility that
permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with
the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters
of credit. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of the Company’s 10%
Senior Notes due 2017 remains outstanding as of such date that has not been refinanced with either permitted refinancing debt or
permitted second lien debt with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement.
As of December 31, 2015 the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the
Credit Agreement.

F-18

The borrowing base under the Credit Agreement is determined by March 31 and September 30 of each year and based
upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. As
of December 31, 2015, the borrowing base was $55 million (subject to the aggregate commitments of the lenders then in effect
and the Company's compliance with the financial covenants thereunder). During January 2016, the borrowing base and the aggregate
commitments of the lenders were reduced to $42 million. Based on the Company's expectations for the first quarter of 2016, the
Company anticipates that, pursuant to the applicable financial covenants, the Company's utilization of the borrowing base will be
limited to 25% of the aggregate commitments of the lenders, or $10.5 million. The next scheduled borrowing base redetermination
is scheduled to occur by March 31, 2016 with additional interim redeterminations to occur on July 31 and December 31 of each
year commencing on July 31, 2016. The Company or the lenders may request two additional borrowing base re-determinations
each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose
a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base
is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base
remains the same or is reduced.

The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries,
including a lien on all equipment and at least 90% of the aggregate total value of the Borrower’s oil and gas properties. Outstanding
balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of
1.0% to 2.0% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale
of 2.0% to 3.0% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime
rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate (subject to a floor of 0.0%) plus 1%. For the
purposes of the definition of alternate base rate only, the adjusted LIBO rate for any day is based on the LIBO Rate at approximately
11:00 a.m. London time on such day. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits
in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory
reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate
equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company
pays commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.

Note 11—Related Party Transactions

Two of the Company’s senior officers, Charles T. Goodson and Stephen H. Green, or their affiliates, are working interest
owners and overriding royalty interest owners and E. Wayne Nordberg and William W. Rucks, IV, two of the Company’s directors,
are working interest owners in certain properties operated by the Company or in which the Company also holds a working interest.
As working interest owners, they are required to pay their proportionate share of all costs and are entitled to receive their
proportionate share of revenues in the normal course of business. As overriding royalty interest owners, they are entitled to receive
their proportionate share of revenues in the normal course of business.

F-19

During 2015, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs,
were disbursed to (received from) Messrs. Goodson and Green, or their affiliates, in the amounts of $(45,000), and $30,000,
respectively, and with respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $300. During 2014, in
their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs.
Goodson and Green, or their affiliates, in the amounts of $80,000 and $116,000, respectively, and with respect to Mr. Nordberg,
costs billed equaled revenues disbursed. During 2013, in their capacities as working interest owners or overriding royalty interest
owners, revenues, net of costs, were disbursed to Messrs. Goodson and Green, or their affiliates, in the amounts of $92,000 and
$269,000, respectively, and with respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $200. No
such disbursements were made to Mr. Rucks during any reported period. With respect to Mr. Goodson, gross revenues attributable
to interests, properties or participation rights held by him prior to joining the Company as an officer and director on September 1,
1998 represent all of the gross revenue received by him during these periods.

In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their
respective working interests. At December 31, 2015, the Company’s joint interest billing receivable included approximately
$10,000 from the related parties discussed above or their affiliates, attributable to their share of costs. This represents less than
1% of the Company’s total joint interest billing receivable at December 31, 2015.

Periodically, the Company charters private aircraft for business purposes. During 2014, the Company paid approximately
$18,200 to a third party operator in connection with the Company’s use of flight hours owned by Charles T. Goodson through a
fractional ownership arrangement with the third party operator. These amounts represent the cost of the hours purchased by
Mr. Goodson. No such amounts were incurred during 2015 and 2013. The Company’s use of flight hours purchased by Mr. Goodson
was pre-approved by the Company’s Audit Committee and there is no agreement or obligation by or on behalf of the Company
to utilize this aircraft arrangement.

Note 12—Ceiling Test Write-down

The Company uses the full cost method to account for its oil and gas properties. Accordingly, the costs to acquire, explore
for and develop oil and gas properties are capitalized. Capitalized costs of oil and gas properties, net of accumulated DD&A and
related deferred taxes, are limited to the estimated future net cash flows from estimated proved oil and gas reserves, including the
effects of cash flow hedges in place, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted
for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to ceiling
test write-down of oil and gas properties in the quarter in which the excess occurs.

In accordance with SEC requirements, the estimated future net cash flows from estimated proved reserves are based on
an average of the first day of the month spot price for a historical 12-month period, adjusted for quality, transportation fees and
market differentials. At December 31, 2015, the prices used in computing the estimated future net cash flows from the Company’s
estimated proved reserves, including the effect of hedges in place at that date, averaged $2.42 per Mcf of natural gas, $50.29 per
barrel of oil and $2.21 per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on the Company's
estimated proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of
approximately $266.6 million during 2015. No such write-down occurred during 2014 or 2013. The Company’s cash flow hedges
in place at December 31, 2015 decreased the ceiling test write-down by approximately $1.1 million.

F-20

Note 13—Other Comprehensive Income

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year

ended December 31, 2014 (in thousands):

Balance as of December 31, 2013

(688) $

(408) $

(1,096)

Gains and Losses on
Cash Flow Hedges

Change in Valuation
Allowance

Total

Other comprehensive income before
reclassifications:

Change in fair value of derivatives

Income tax effect

Net of tax

Amounts reclassified from accumulated
other comprehensive income:

Oil and gas sales

Income tax effect

Net of tax

Net other comprehensive income
Balance as of December 31, 2014

6,683
(2,487)
4,196

3,044
(1,132)
1,912

6,108
5,420

408

—

408
— $

6,683
(2,079)
4,604

3,044
(1,132)
1,912

6,516
5,420

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year

ended December 31, 2015 (in thousands):

Balance as of December 31, 2014

Other comprehensive income before reclassifications:

Change in fair value of derivatives

Income tax effect

Net of tax

Amounts reclassified from accumulated other comprehensive income:

Oil and gas sales

Income tax effect

Net of tax

Net other comprehensive loss

Balance as of December 31, 2015

Note 14—Income Taxes

Gains and Losses
on Cash Flow
Hedges

5,420

9,991
(3,716)
6,275

(17,114)
6,366
(10,748)
(4,473)
947

The Company typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected
to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of
ceiling test write-downs, the Company has incurred a cumulative three-year loss. Because of the impact the cumulative loss had
on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the realizability
of its deferred tax assets based on the future reversals of existing deferred tax liabilities. The Company had a valuation allowance
of $143.5 million as of December 31, 2015.

F-21

An analysis of the Company’s deferred taxes follows (amounts in thousands):

December 31,

2015

2014

2013

Net operating loss carryforwards

Percentage depletion carryforward

Alternative minimum tax credits

Contributions carryforward and other

Temporary differences:

Oil and gas properties

Asset retirement obligation

Derivatives

Share-based compensation

Valuation allowance

Deferred taxes

24,014

10,592

784

266

90,291

15,831

(561)

2,291

(143,508)

17,705

10,206

784

241

(15,439)
20,449
(3,211)
2,560
(33,295)

— $

21,810

8,645

784

189

(7,248)
18,056

408

2,887
(45,531)
—

At December 31, 2015, the Company had approximately $77.1 million of operating loss carryforwards, of which $12.6
million relates to excess tax benefits with respect to share-based compensation that have not been recognized in the financial
statements. If not utilized, approximately $8.7 million of such carryforwards would expire in 2025 and the remainder would expire
by the year 2034. The Company has available for tax reporting purposes $30.3 million in statutory depletion deductions that may
be carried forward indefinitely.

Income tax expense (benefit) for each of the years ended December 31, 2015, 2014 and 2013 was different than the

amount computed using the Federal statutory rate (35%) for the following reasons (amounts in thousands):

For the Year Ended December 31,

2015

2014

2013

Amount computed using the statutory rate

(102,257) $

9,887

5,041

Increase (reduction) in taxes resulting from:

State & local taxes

Percentage depletion carryforward

Non-deductible stock option expense (1)

Share-based compensation (2)

Other

Change in valuation allowance

Income tax expense (benefit)

(6,477)
(404)
90

1,317

113

110,244

2,626

904
(1,564)
213

90
(643)
(11,828)
(2,941)

317
(1,323)
115

780

1,132
(5,742)
320

(1) Relates to compensation expense recognized on the vesting of Incentive Stock Options.
(2) Relates to the write-off of deferred tax assets associated with share-based compensation that will not be deductible for tax

purposes.

Note 15—Commitments and Contingencies

The Company is a party to ongoing litigation in the normal course of business. While the outcome of lawsuits or other
proceedings against the Company cannot be predicted with certainty, management believes that the effect on its financial condition,
results of operations and cash flows, if any, will not be material.

F-22

Lease Commitments

The Company has operating leases for office space and equipment, which expire on various dates through 2023. Future

minimum lease commitments as of December 31, 2015 under these operating leases are as follows (in thousands):

2016

2017

2018

2019

2020

Thereafter

1,419

1,310

452

422

417

1,225

5,245

Total rent expense under operating leases was approximately $1.7 million, $1.6 million and $1.4 million in 2015, 2014

and 2013, respectively.

F-23

Note 16—Supplementary Information on Oil and Gas Operations—Unaudited

The following tables disclose certain financial data relative to the Company’s oil and gas producing activities, which are

located onshore and offshore in the continental United States:

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
(amounts in thousands)

Acquisition costs:

Proved (1)

Unproved (1)

Exploration costs:

Proved

Unproved

Development costs

Capitalized general and administrative and interest costs

For the Year-Ended December 31,

2015

2014

2013

2,287

3,064

$ 177,880

2,550

39,164

35,008

29,322

7,677

9,888

12,881

67,297

13,515

55,722

22,121

34,344

20,112

41,328

19,911

Total costs incurred

64,605

$ 200,883

$ 328,583

Accumulated depreciation, depletion and
amortization (DD&A)
Balance, beginning of year

Provision for DD&A

Ceiling test writedown

Sale of proved properties and other (2) (3)

Balance, end of year

DD&A per Mcfe

For the Year-Ended December 31,

2015

2014

2013

(1,648,060) $
(62,138)
(266,562)
819,305
(1,157,455) $

(1,553,044) $
(86,406)
—
(8,610)
(1,648,060) $

(1,472,244)
(69,357)
—
(11,443)
(1,553,044)

1.82

1.99

1.82

(1) During 2014, the Company entered into a joint venture in Louisiana for an aggregate purchase price of $24 million for an
approximate 30,000 acre leasehold position. During 2013, the Company closed on the Gulf of Mexico Acquisition for an
aggregate cash purchase price of $188.8 million (see Note 2). Additionally, the Company acquired 13,500 net unevaluated
acres in Oklahoma targeting the Woodford Shale in 2013.

(2) During 2015, the Company sold its Woodford and Mississippian Lime assets for an aggregate cash purchase price of $274.1

million (see Note 2).

(3) During 2015, the Company sold its Fort Trinidad assets for net proceeds of approximately $0.5 million and its East
Haynesville assets for net proceeds of approximately $0.1 million. During 2014, the Company sold its Eagle Ford assets
for net proceeds of approximately $9.8 million. During 2013, the Company sold 50% of its saltwater disposal systems and
related surface assets in the Woodford for net proceeds of approximately $10.4 million and its non-operated Wyoming
assets for a cash purchase price of $1.0 million.

At December 31, 2015 and 2014, unevaluated oil and gas properties totaled $12.5 million and $109.1 million, respectively,
and were not subject to depletion. Unevaluated costs at December 31, 2015 included $0.2 million of costs related to two exploratory
wells in progress at year-end. These costs are expected to be transferred to evaluated oil and gas properties during 2016 upon the
completion of drilling. At December 31, 2014, unevaluated costs included $16.8 million related to 16 exploratory wells in progress.
All of these costs were transferred to evaluated oil and gas properties during 2015. The Company capitalized $4.7 million, $10.0
million and $6.6 million of interest during 2015, 2014 and 2013, respectively. Of the total unevaluated oil and gas property costs
of $12.5 million at December 31, 2015, $(3.1) million, or (25)%, was incurred in 2015, $3.6 million, or 29%, was incurred in 2014
and $12.1 million, or 96%, was incurred in prior years. The Company expects that the majority of the unevaluated costs at

F-24

December 31, 2015 will be evaluated within the next 3 years, including $0.2 million that the Company expects to be evaluated
during 2016.

Oil and Gas Reserve Information

The Company’s net proved oil and gas reserves at December 31, 2015 have been estimated by independent petroleum

engineers in accordance with guidelines established by the SEC using a historical 12-month average pricing assumption.

The estimates of proved oil and gas reserves constitute those quantities of oil, gas,and natural gas liquids, which, by
analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a
given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government
regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. However, there are
numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and
timing of development expenditures. The following reserve data represents estimates only and should not be construed as being
exact. In addition, the present values should not be construed as the current market value of the Company’s oil and gas properties
or the cost that would be incurred to obtain equivalent reserves.

F-25

The following table sets forth an analysis of the Company’s estimated quantities of net proved and proved developed oil

(including condensate), gas and natural gas liquid reserves, all located onshore and offshore in the continental United States:

Proved reserves as of December 31, 2012

Revisions of previous estimates

Extensions, discoveries and other additions

Purchase of producing properties

Sale of reserves in place

Production

Proved reserves as of December 31, 2013

Revisions of previous estimates

Extensions, discoveries and other additions

Sale of reserves in place

Production

Proved reserves as of December 31, 2014

Revisions of previous estimates

Extensions, discoveries and other additions

Sale of reserves in place

Production

Proved reserves as of December 31, 2015

Proved developed reserves

As of December 31, 2013

Oil
in
MBbls

NGL
in
MMcfe

Natural Gas
in
MMcf

Total
Reserves
in MMcfe

1,635
(156)
434

1,833
(34)
(681)
3,031
(37)
475
(229)
(803)
2,437
(211)
163
(54)
(529)
1,806

24,366

804

6,099

1,915

—
(4,754)
28,430

2,894

49,990
(334)
(7,482)
73,498
(3,571)
16,078
(45,692)
(5,487)
34,826

188,264

38,383

30,429

22,274
(15)
(29,226)
250,109

9,976

82,364
(2,396)
(31,028)
309,025
(9,852)
45,645
(186,972)
(25,502)
132,344

222,441

38,247

39,132

35,187
(218)
(38,066)
296,723

12,650

135,205
(4,105)
(43,325)
397,148
(14,698)
62,702
(232,988)
(34,160)
178,004

2,709

23,173

163,728

203,152

As of December 31, 2014

2,089

42,584

182,567

237,688

As of December 31, 2015

1,549

15,792

78,533

103,615

Proved undeveloped reserves

As of December 31, 2013

As of December 31, 2014

As of December 31, 2015

Year Ended December 31, 2015

322

348

257

5,257

86,381

93,571

30,914

126,458

159,460

19,034

53,811

74,389

During 2015, the Company’s estimated proved reserves decreased by 55%. Sales of reserves in place was primarily due
to the divestiture of the majority of the Company's Woodford and Mississippian Lime assets. Extensions, discoveries and other
additions of 63 Bcfe were primarily due to successful drilling programs in the Company's Oklahoma and East Texas fields. The
Company added approximately 17 Bcfe of proved reserves in Oklahoma and 44 Bcfe in Texas. Overall, the Company had a 95%
drilling success rate during 2015 on 56 gross wells drilled.

F-26

Year Ended December 31, 2014

During 2014, the Company’s estimated proved reserves increased by 34%. Extensions, discoveries and other additions
of 135 Bcfe were primarily due to successful drilling programs in the Company's Oklahoma and East Texas fields and its Thunder
Bayou discovery. The Company added approximately 72 Bcfe of proved reserves in Oklahoma, 46 Bcfe in Texas and 15 Bcfe in
the Gulf Coast. Overall, the Company had a 91% drilling success rate during 2014 on 58 gross wells drilled.

Year Ended December 31, 2013

Extensions, discoveries and other additions were primarily due to the success of the Company's Oklahoma, Texas and
Gulf Coast drilling programs. The Company added approximately 23 Bcfe of proved reserves in Oklahoma, 5 Bcfe in the Gulf
Coast and 10 Bcfe in Texas. Revisions of previous estimates were primarily a result of the increase in the historical 12-month
average price per Mcf of natural gas used to calculate estimated proved reserves, which was $3.11 per Mcf at December 31, 2013 as
compared to $2.20 per Mcf at December 31, 2012. The 35 Bcfe added through purchase of producing properties relates to the
Company's Gulf of Mexico Acquisition (See Note 2).

The following tables (amounts in thousands) present the standardized measure of future net cash flows related to proved
oil and gas reserves together with changes therein, as defined by ASC Topic 932. Future production and development costs are
based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a
10% annual discount rate.

Standardized Measure

Future cash flows

Future production costs

Future development costs

Future income taxes

Future net cash flows

10% annual discount

Standardized measure of discounted future net cash flows $

Changes in Standardized Measure

December 31,

2015

2014

2013

487,834
(171,678)
(116,591)
—

199,565
(71,880)
127,685

1,711,404
(372,690)
(244,784)
(121,192)
972,738
(424,176)
548,562

1,243,627
(295,666)
(185,188)
(37,404)
725,369
(274,189)
451,180

Standardized measure at beginning of year

Sales and transfers of oil and gas produced, net of production costs

Changes in price, net of future production costs

Extensions and discoveries, net of future production and development costs

Changes in estimated future development costs, net of development costs
incurred during this period

Revisions of quantity estimates

Accretion of discount

Net change in income taxes

Purchase of reserves in place

Sale of reserves in place

Changes in production rates (timing) and other

Net increase (decrease) in standardized measure

Standardized measure at end of year

F-27

Year Ended December 31,

2015

2014

2013

548,562

451,180

230,823

(55,849)
(267,710)
70,928

31,007
(14,427)
60,071

52,149

—
(194,454)
(102,592)
(420,877)
127,685

(173,540)
37,204

237,290

(134,184)
55,601

70,181

11,094

25,591

47,130
(32,034)
—
(7,240)
(48,113)
97,382

(25,389)
58,508

23,776
(13,182)
191,964
(411)
(6,507)
220,357

548,562

451,180

The historical twelve-month average prices of oil, gas and natural gas liquids used in determining standardized measure were:

Oil, $/Bbl

Ngls, $/Mcfe

Natural Gas, $/Mcf

2015

2014

2013

$50.29

2.24

2.41

$96.45

4.11

3.80

$106.19

5.10

3.11

Note 17 - Summarized Quarterly Financial Information - Unaudited

Summarized quarterly financial information is as follows (amounts in thousands except per share data):

2015:

Revenues

Loss from operations (1)

Loss available to common stockholders (1)

Earnings per share:

Basic

Diluted

2014:

Revenues

Income from operations

Income available to common stockholders

Earnings per share:

Basic

Diluted

Quarter Ended

March 31

June 30

September 30 December 31

33,451 $

(121,887)
(122,240)

32,550 $
(57,796)
(61,083)

26,872 $
(50,617)
(51,910)

23,096
(61,864)
(64,696)

(1.89) $
(1.89) $

(0.94) $
(0.94) $

(0.80) $
(0.80) $

(0.98)
(0.98)

59,966 $

60,581 $

56,486 $

47,988

11,323

10,043

10,879

9,592

5,569

4,671

0.15 $

0.07 $

478

1,745

0.02

(1) Loss from operations and net loss available to common stockholders reported during the three months ended March 31,
June 30, September 30 and December 31, 2015 included pretax ceiling test write-downs of $108.9 million, $65.5 million, $40.2
million and $51.9 million, respectively. Additionally, loss from operations and net loss available to common stockholders
reported during the three months ended June 30, 2015 included a pretax gain on sale of oil and gas properties of $21.5 million.

F-28

[THIS PAGE INTENTIONALLY LEFT BLANK]

Corporate Profile

Letter To Shareholders

CORPORATE INFORMATION

BOARD OF DIRECTORS

Charles T. Goodson
Chairman of the Board,
Chief Executive Officer, and President

W.J. Gordon III *#^
President, CEO, and Founder of TGA Global Consulting Group

Michael L. Finch *#^
Dear Fellow Shareholders:
Private Investments

CORPORATE ADDRESS

PetroQuest Energy, Inc.
400 East Kaliste Saloom Road, Suite 6000
Lafayette, Louisiana 70508
Telephone: (337) 232-7028
Fax: (337) 232-0044
Web: www.petroquest.com

Core Assets

Oklahoma Woodford
Reserves: 11%
Production: 27%

Reserves: 64%
Production: 33%

Reserves: 25%
Production: 40%

E. Wayne Nordberg *#^
Hollow Brook Associates, LLC

William W. Rucks, IV *#^
Private Investments

* Member of the Compensation Committee
# Member of the Audit Committee

SENIOR MANAGEMENT

Charles T. Goodson
Chairman of the Board,
Chief Executive Officer, and President

J. Bond Clement
Executive Vice President
Chief Financial Officer, and Treasurer

Art M. Mixon
Executive Vice President
Operations and Production

Tracy Price
Executive Vice President
Business Development & Land

Stephen H. Green
Senior Vice President
Significant Transactions
Exploration

Mark K. Castell
Vice President - Oklahoma Assets

Edgar A. Anderson
Vice President - ArkLaTex

EXPLORATION OFFICES

Charles T. Goodson
Chairman, President & CEO

1800 Hughes Landing Blvd., Suite 200
The Woodlands, Texas 77380
Telephone: (281) 465-3900
Fax: (281) 465-3999

1717 S. Boulder, Suite 201
Tulsa, Oklahoma 74119
Telephone: (918) 582-2770
Fax: (918) 582-2778

American Stock Transfer & Trust Company
59 Maiden Lane
New York, New York 10038
Telephone: (718) 921-8145

Ernst & Young LLP
New Orleans, Louisiana 70170

LEGAL COUNSEL

Quality Assets

Porter & Hedges, LLP
Houston, Texas 77002

ANNUAL MEETING

Onebane Law Firm
Lafayette, Louisiana 70508

The Company’s Annual Meeting of Stockholders
will be held at 9:00 A.M. CDT on May 18, 2016, at the
City Club at River Ranch at 221 Elysian Fields Drive,
Lafayette, Louisiana, 70508.

COMMON STOCK LISTING

FORM 10-K

Listed on NYSE as PQ

2015 Annual Report

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www.PETROQUEST.COM

NYSE:PQ

2015
2015

Annual Report