10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2018

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	72-1440714
State of incorporation	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	Name of each exchange on which registered
None	None

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     ý  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

ý   Yes     ¨  No

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

¨   Yes     ý  No

As indicated above, the registrant is not required to file reports pursuant to the Securities Exchange Act of 1934. However, the registrant has filed all Exchange Act reports for the preceding 12 months.

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

ý  Yes     ¨   No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x	Smaller reporting company	x
		Emerging growth company	¨

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

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

¨  Yes    ý   No

The aggregate market value of the voting common equity held by non-affiliates of the Predecessor registrant as of June 29, 2018, based on the $0.228 per share closing price for the registrant's common stock as quoted on the OTCQX market, was approximately $5,424,000 (for purposes of this disclosure, the registrant assumed its directors and executive officers were affiliates).

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

x Yes ¨ No

As indicated above, the registrant is not required to file reports pursuant to the Securities Exchange Act of 1934. However, the registrant has filed all Exchange Act reports for the preceding 12 months.

As of March 10, 2019, the Successor registrant had outstanding 9,200,000 shares of Class A Common Stock, one share of Class B Common Stock and one share of Class C Common Stock.

Documents incorporated by reference: None.

Table of Contents

	Page No.
PART I
Items 1 and 2 Business and Properties	6
Item 1A. Risk Factors	20
Item 1B. Unresolved Staff Comments	33
Item 3. Legal Proceedings	33
Item 4. Mine Safety Disclosures	34
PART II
Item  5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6. Selected Financial Data	34
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	45
Item 8. Financial Statements and Supplementary Data	45
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	45
Item 9A. Controls and Procedures	45
Item 9B. Other Information	46
PART III
Item 10. Directors, Executive Officers and Corporate Governance	47
Item 11. Executive Compensation	51
Item  12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	55
Item 13. Certain Relationships and Related Transactions, and Director Independence	57
Item 14. Principal Accounting Fees and Services	58
PART IV
Item 15. Exhibits, Financial Statement Schedules	59
Item 16. Form 10-K Summary	65
Index to Financial Statements	70

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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 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:

• risks and uncertainties associated with our Chapter 11 proceedings;

• the likelihood that our Chapter 11 proceedings may have disrupted our business;

• the possibility that the assumptions and analyses used to develop our Chapter 11 plan of reorganization may prove to be incorrect;

• the likelihood that our historical financial information may no longer be indicative of our future financial performance;

• the possibility that our new board of directors may have a different strategy and plan for the Company's future;

• the possibility that our anticipated fresh start accounting could result in a ceiling test writedown;

• our ability to attract and retain key personnel may be affected by our emergence from bankruptcy;

• the volatility of oil and natural gas prices;

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

• 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 the Exit Facility (as defined below) and restrictive debt covenants;

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

• our responsibility for offshore decommissioning liabilities for offshore interests we no longer own;

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

• approximately 44% 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;

• our ability to successfully develop our inventory of undeveloped acreage;

• the possibility of a substantial lease renewal cost or the loss of our leases and prospective drilling opportunities that could result from a failure to drill sufficient wells to hold our undeveloped acreage;

• 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;

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

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

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

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• our ability to market our oil and natural gas production;

• changes in laws and governmental regulations and increases in insurance costs or decreases in insurance availability directed toward our business;

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

• 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 environmental compliance costs and environmental liabilities;

• the impact of potential cybersecurity threats;

• the loss of our information and computer systems;

• the impact of terrorist activities on global economies;

• the possibility that the interests of our significant stockholders could be in conflict with the interest of our other stockholders;

• no meaningful trading market for our Class A Common Stock and the volatility of the market price for our Class A Common Stock;

• the restrictions in our certificate of incorporation and bylaws which could delay or prevent a change of control of our company; and

• the restrictions on our ability to pay dividends with respect to our common stock.

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 66.

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Part I

Item 1 and 2. Business and Properties

Overview

PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with primary operations in Texas and Louisiana. 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 with our acquisition of the Carthage Field in East Texas. From 2005 through 2015, we further implemented this strategy by focusing our efforts in the Woodford Shale play in Oklahoma. In response to lower commodity prices and to strengthen our balance sheet, we sold all of our Oklahoma assets in three transactions during 2015 and 2016. In December 2017, we acquired approximately 24,600 gross acres in central Louisiana targeting the Austin Chalk to provide greater exposure to oil production and reserves. During January 2018, we sold all of our Gulf of Mexico assets to further reduce our liabilities and strengthen our liquidity position.

Our liquidity position has been negatively impacted by lower commodity prices beginning in 2014. In response to the lower commodity prices, we executed numerous actions beginning in 2015 aimed at increasing liquidity, reducing overall debt levels and other liabilities, and extending debt maturities. Despite these actions, our overall liquidity position and our cash available for capital expenditures continued to be negatively impacted by weak natural gas prices, declining production and increased cash interest expense on outstanding indebtedness.

As a result of the forgoing, we engaged in discussions and negotiations with the lenders under the Multidraw Term Loan Agreement (as defined below), certain holders of the 2021 Notes (as defined below) and the 2021 PIK Notes (as defined below), and their legal and financial advisors regarding various alternatives with respect to our capital structure and financial position, including our significant amount of indebtedness and the August 15, 2018 interest payments overdue on our 2021 PIK Notes and 2021 Notes.

Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

As a result of the forgoing discussions and negotiations, on November 6, 2018 (the “Petition Date”), we and our wholly-owned direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions (collectively, the “Petition,” and the cases commenced thereby, the “Chapter 11 Cases”) seeking relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).

In connection with the Chapter 11 filing, on the Petition Date, the Debtors entered into a restructuring support agreement (the “Restructuring Support Agreement”) with (i) holders of 81.83% of our 10% Second Lien Senior Secured Notes due 2021 (the “2021 Notes”), (ii) holders of 84.76% of our 10% Second Lien Senior Secured PIK Notes due 2021 (the “2021 PIK Notes”) and (iii) each of the lenders, or investment advisors or managers for the account of each of the lenders under our multidraw term loan agreement (the "Multidraw Term Loan Agreement"), pursuant to which such parties agreed to support the Plan (as defined below).

On January 31, 2019, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Debtors’ First Amended Chapter 11 Plan of Reorganization, as Immaterially Modified as of January 28, 2019 (as amended, modified or supplemented from time to time, the “Plan”) under Chapter 11 of the Bankruptcy Code. On February 8, 2019 (the “Effective Date”), the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases. On the Effective Date, TDC Energy, LLC, Pittrans, Inc. and Sea Harvester Energy Development, L.L.C. were dissolved. The remaining Debtors (collectively, the "Reorganized Debtors") continue in existence. In this Form 10-K, we may refer to the Company prior to the Effective Date as the “Predecessor,” and on and after the Effective Date as the “Successor.”

On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Company:

• Adopted an amended and restated certificate of incorporation and bylaws;

• Appointed four new members to the Successor’s board of directors to replace all of the directors of the Predecessor, other than the director also serving as Chief Executive Officer, who was re-appointed pursuant to the Plan;

• Canceled all of the Predecessor’s common stock and 6.875% Series B Cumulative Convertible Perpetual Preferred Stock with the former holders thereof not receiving any consideration in respect of such stock;

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• Issued to the former holders of the Predecessor’s 2021 Notes and 2021 PIK Notes (collectively the “Old Notes”), in exchange for the cancellation and discharge of the Old Notes:

◦ 8,900,000 shares of the Successor’s Class A Common Stock; and

◦ $80.0 million of the Successor’s 10% Senior Secured PIK Notes due 2024 (the “2024 PIK Notes”);

• Issued 300,000 shares of the Successor’s Class A Common Stock to certain former holders of the Old Notes for their commitment to backstop the Exit Facility (as defined below);

• Issued to the Class B Holder (as defined in the Successor’s amended and restated certificate of incorporation) one share of the Successor’s Class B Common Stock, which confers certain rights to elect directors and certain drag-along rights;

• Issued to the Class C Holder (as defined in the Successor’s amended and restated certificate of incorporation) one share of the Successor’s Class C Common Stock, which confers certain rights to elect directors and certain drag-along rights;

• Entered into a new $50 million senior secured Term Loan Agreement (the “Exit Facility”) upon the repayment and termination of the Predecessor’s Multidraw Term Loan Agreement;

• Entered into a registration rights agreement (the “Registration Rights Agreement”) with certain holders of the Successor’s Class A Common Stock and 2024 PIK Notes; and

• Adopted a new management incentive plan (the “2019 Long Term Incentive Plan”) for officers, directors and employees of the Successor and its subsidiaries, pursuant to which 1,344,000 shares of the Successor’s Class A Common Stock were reserved for issuance.

The foregoing is a summary of the substantive provisions of the Plan and related transactions and is not intended to be a complete description of, or a substitute for a full and complete reading of the Plan and the other documents referred to above. See “Note 2- Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” in Item 8. Financial Statements and Supplementary Data of this Form 10-K for a discussion of our bankruptcy and resulting reorganization.

Business Strategy

Focus Capital Toward More Predictable Onshore Assets. As a result of the sale of our Gulf of Mexico assets in January 2018, our asset base is now exclusively comprised of onshore assets in Texas and Louisiana. We plan to continue to focus the majority of our capital spending developing our lower-risk Cotton Valley acreage in East Texas where we believe the less complex geology, combined with the large inventory of offsetting vertical and horizontal well data, offers greater predictability in increasing production and proved reserves. With respect to horizontal drilling operations in the Carthage Field, we have a 100% five year drilling success rate on 21 gross wells drilled. Additionally, our East Texas acreage position provides a significant inventory of future drilling locations, which we expect to develop over a long-term drilling campaign. We also expect to drill our initial well in our Austin Chalk acreage in 2019, where we have substantial geologic and reservoir data from a multitude of vertical and horizontal wells in the area. We plan to apply our latest drilling and completion techniques to consistently improve the economic development of our resource potential.

Maintain Our Financial Flexibility. We strive to consistently fund our capital expenditures with a combination of cash flow from operations, cash on hand, asset sales and certain joint venture arrangements rather than increasing our total debt. Because we operate approximately 82% of our total estimated proved reserves and manage the drilling and completion activities on an additional 18% of such reserves, we expect to be able to control the timing of a substantial portion of our capital investments in order to better align our sources and uses of capital.

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 weight our capital allocation to lower risk development activities and reduce the capital allocated to higher risk exploration activities. At December 31, 2018, approximately 94% of our estimated proved reserves were located in longer life and lower risk basins in East Texas and 6% were located in the shorter life, but higher flow rate reservoirs in the Gulf Coast Basin. In terms of production diversification, during 2018, 55% of our production was derived from longer life basins. Our 2018 production was comprised of 75% natural gas, 9% oil and 16% natural gas liquids. We believe that the development of our Austin Chalk acreage in central Louisiana will allow us to achieve a more balanced commodity profile as these assets are believed to have a greater percentage of oil production than our East Texas assets.

Concentrate in Core Operating Areas and Build Scale. With the sale of our Gulf of Mexico assets, we have substantially reduced our operational footprint allowing us to concentrate our efforts in fewer areas. We plan to focus on our operations in East

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Texas and our Austin Chalk acreage. We also expect to continue to harvest cash flow from our Gulf Coast producing assets as they are expected to require minimal capital expenditures. 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 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.

2018 Financial and Operational Summary

As a result of our Chapter 11 reorganization activities described above, our capital spending and operating activity was significantly reduced in 2018. During 2018, we invested $16.1 million primarily related to two completions in our East Texas drilling program, various plugging and abandonment projects and leasing efforts in the Austin Chalk. These activities were financed through cash on hand and our cash flow from operations. During 2018, our production decreased23% to 21.3 Bcfe due primarily to the sale of our Gulf of Mexico assets in January 2018. Our estimated proved reserves at December 31, 2018decreased16% from 2017 as discussed in greater detail below.

Oil and Gas Reserves

The following table sets forth certain information about our estimated proved reserves as of December 31, 2018:

	Oil (MBbls)	NGL (Mmcfe)	Natural Gas (Mmcf)	Total Mmcfe*
Proved Developed	567	10,220	47,516	61,143
Proved Undeveloped	619	6,802	58,648	69,162
Total Proved	1,186	17,022	106,164	130,305

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

Our estimated proved reserves at December 31, 2018decreased16% from 2017 totaling 1.2 MMBbls of oil, 17.0 Bcfe of natural gas liquids (Ngls) and 106.2 Bcf of natural gas. At December 31, 2018, our standardized measure of our discounted cash flows, which includes the estimated impact of future income taxes, totaled $124.0 million. We had a pre-tax present value, discounted at 10%, of the estimated future net revenues based on 12-month, first day of month, average prices during 2018 (“PV-10”) of $124.0 million. See the reconciliation of standardized measure of discounted cash flows to PV-10 below. The decrease in reserves was primarily the result of the sale of our Gulf of Mexico assets in January 2018 resulting in a reduction of 10.1 Bcfe.

Our standardized measure of discounted cash flows and PV-10 utilized prices (adjusted for field differentials) for the years ended December 31, 2018 and 2017 as follows:

	12/31/2018	12/31/2017
Oil per Bbl	$68.71	$52.46
Natural gas per Mcf	$3.13	$3.03
Ngl per Mcfe	$4.08	$3.23

    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, 2018. Our internal reservoir engineering staff is managed by an individual with over 36 years of industry experience as a reservoir and production engineer, including sixteen years as the Reservoir Engineering Manager for PetroQuest.

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 generally accepted accounting principles ("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.

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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 members of our Board of Directors with oil and gas technical experience.

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 and completed 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 100% drilling success rate on 21 gross wells drilled in East Texas where 100% of our PUD reserves are currently booked. Furthermore, because all of our PUD reserves 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.

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.     

As of December 31, 2018, our PUD reserves totaled 69.2 Bcfe, a 13%decrease from our PUD reserves at December 31, 2017. During 2018, we spent $4.2 million converting 6.5 Bcfe of PUD reserves at December 31, 2017 to proved developed reserves at December 31, 2018. In addition at year-end 2018, drilling was in progress on three PUD locations which resulted in the conversion of 13.6 Bcfe to proved developed reserves in early 2019.    

The following table presents an analysis of the change in our PUD reserves from December 31, 2017 to December 31, 2018:

	MMcfe
PUD reserve balance at December 31, 2017	79,506
Conversions to proved developed	(6,514	)
Net additions from extensions, discoveries and revisions	3,494
Divestitures	(7,324	)
PUD reserve balance at December 31, 2018	69,162

During 2018, we added 11.1 Bcfe of PUD reserves as a result of third party drilling, as well as leasing efforts which provided two additional PUD locations. All of our PUD reserves at December 31, 2018 were associated with the future development of our East Texas properties. We expect all of our PUD reserves at December 31, 2018 to be developed over the next five years. However, our PUD reserve inventory does not encompass all drilling activities over the next five years. We expect to continue to allocate capital to projects that do not have proved reserves ascribed to them. At December 31, 2018, 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 $24.7 million in 2019, $6.0 million in 2020, $0.2 million in 2021, $27.3 million in 2022 and $11.9 million in 2023. During 2019, we expect to convert approximately 26.7 Bcfe of PUDs at December 31, 2018 to proved developed reserves, including 13.6 Bcfe of PUD reserves that have already been converted to proved developed in early 2019.

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The estimated cash flows from our proved reserves at December 31, 2018 were as follows:

	Proved Developed (M$)		Proved Undeveloped (M$)		Total Proved (M$)
Estimated pre-tax future net cash flows (1)	$	131,909	$	105,601	$	237,510
Discounted pre-tax future net cash flows (PV-10) (1)	$	87,543	$	36,482	$	124,025
Total standardized measure of discounted future net cash flows					$	124,025

(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 that 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 pre-tax future net cash flows to standardized measure of discounted cash flows as of December 31, 2018:

	Total Proved (M$)
Estimated pre-tax future net cash flows	$	237,510
10% annual discount	113,485
Discounted pre-tax future net cash flows	124,025
Future income taxes discounted at 10%	—
Standardized Measure of discounted future net cash flows	$	124,025

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, 2018 and 2017.

	2018		2017
	Reserves	Production	Reserves	Production
Gulf Coast	8.3	9.1	13.8	10.6
Gulf of Mexico (1)	—	0.4	10.5	6.9
East Texas	122.0	11.8	131.6	10.1
	130.3	21.3	155.9	27.6

(1) In January 2018, we sold all of our producing Gulf of Mexico assets.

East Texas

During 2018, we invested $8.2 million in our East Texas properties where we completed two gross wells, achieving a 100% success rate. Production from our East Texas assets averaged 32.3 MMcfe per day during 2018, a 16%increase from 2017 average daily production; however, our estimated proved reserves decreased 7% from 2017 primarily due to 7.3 Bcfe of reserves sold during 2018.

Gulf Coast

During 2018, we invested $7.6 million in this core area, including additional acquisitions of Austin Chalk acreage in central Louisiana. Production from this area decreased 14% from 2017 totaling 24.9 MMcfe per day in 2018 due to normal production declines. Our estimated proved reserves in this area at year end 2018 decreased 40% from 2017 primarily as a result of the 9.1 Bcfe of production in 2018.

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Gulf of Mexico

We sold our assets in this core area in January 2018. See Note 3 - Acquisitions and Divestitures.

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.

A portion of the natural gas production that we operate in East Texas is committed to a minimum volumetric delivery contract with a third party pipeline company. Under the terms of the agreement, we are required to deliver 11.0 Bcf of natural gas in each of the twelve-month periods ended December 31, 2019, 2020 and 2021, respectively. Based upon our projected drilling plans, current estimated proved developed reserves and production, we expect that this commitment will be met.

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 2018, one customer accounted for 26%, one accounted for 21%, one accounted for 16% and one accounted for 12% of our oil and natural gas revenue. During 2017, one customer accounted for 29% and one accounted for 24% of our oil and natural gas revenue. During 2016, one customer accounted for 23%, one accounted for 17%, one accounted for 14% and one accounted for 10% 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.

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Production, Pricing and Production Cost Data

The following table sets forth our production, pricing and production cost data during the periods indicated. Our core area of East Texas represented approximately 94% of our total estimated proved reserves at December 31, 2018. The Gulf Coast area represented less than 10% of our total estimated proved reserves at December 31, 2018, but represented 25% or more of our total production for the year ended December 31, 2018.

	Year Ended December 31,
	2018		2017			2016
Production:
Oil (Bbls):
Gulf Coast	208,162		235,639			127,344
Gulf of Mexico (1)	18,825		304,384			336,559
East Texas	98,961		51,529			38,154
Other (2)	—		6			144
Total Oil (Bbls)	325,948		591,558			502,201
Gas (Mcf):
Gulf Coast	5,986,675		7,352,273			5,075,444
Gulf of Mexico (1)	292,863		4,644,749			3,521,044
East Texas	9,710,072		7,617,452			6,350,712
Other (2)	23,282		(3,510		)	1,669,378
Total Gas (Mcf)	16,012,892		19,610,964			16,616,578
NGL (Mcfe):
Gulf Coast	1,866,425		1,787,950			1,039,368
Gulf of Mexico (1)	20,759		466,608			356,245
East Texas	1,479,205		2,198,165			2,471,936
Other (2)	—		94			3,398
Total NGL (Mcfe)	3,366,389		4,452,817			3,870,947
Total Production (Mcfe):
Gulf Coast	9,102,072		10,554,057			6,878,876
Gulf of Mexico (1)	426,572		6,937,661			5,896,643
East Texas	11,783,043		10,124,791			9,051,572
Other (2)	23,282		(3,380		)	1,673,640
Total Production (Mcfe)	21,334,969		27,613,129			23,500,731
Average sales prices (3):
Oil (per Bbl):
Gulf Coast	$	70.18	$	53.19		$	40.91
Gulf of Mexico (1)	65.03		52.63			41.41
East Texas	66.91		52.47			38.35
Other (2)	—		46.38			37.85
Total Oil (per Bbl)	68.89		52.84			41.05
Gas (per Mcf)
Gulf Coast	3.20		3.09			2.40
Gulf of Mexico (1)	3.03		3.04			2.09
East Texas	3.08		2.97			2.31
Other (2)	3.09		2.29			1.17
Total Gas (per Mcf)	3.12		3.03			2.18
NGL (per Mcfe)
Gulf Coast	5.14		4.45			3.18
Gulf of Mexico (1)	6.73		3.90			2.97
East Texas	3.77		2.88			1.50
Other (2)	—		3.63			5.22
Total NGL (per Mcfe)	4.55		3.62			2.09
Total Per Mcfe:
Gulf Coast	4.76		4.09			3.01
Gulf of Mexico (1)	5.28		4.61			3.79
East Texas	3.57		3.12			2.19
Other (2)	3.09		2.20			1.18

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Total Per Mcfe	4.11	3.87	2.76
Average Production Cost per Mcfe (4):
Gulf Coast	0.67	0.67	0.70
Gulf of Mexico (1)	1.58	2.20	2.43
East Texas	1.16	1.08	0.89
Other (2)	6.77	11.55	0.80
Total Average Production Cost per Mcfe	0.96	1.20	1.21

(1) In January 2018, we sold all of our Gulf of Mexico assets.

(2) Includes Oklahoma-Woodford.

(3) Does not include the effect of hedges.

(4) Production costs do not include production taxes.

Oil and Gas Producing Wells    

The following table details the productive wells in which we owned an interest as of December 31, 2018:

	Gross	Net
Productive Wells:
Oil:
Gulf Coast	1	0.08
East Texas	—	—
	1	0.08
Gas:
Gulf Coast	3	1.20
East Texas	69	41.97
	72	43.17
Total	73	43.25

Of the 73 gross productive wells at December 31, 2018, none were dual completions.

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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.

	2018		2017		2016
	Gross	Net	Gross	Net	Gross	Net
Exploratory:
Productive:
Gulf Coast Basin	—	—	—	—	—	—
East Texas	—	—	2	1.53	—	—
Other (1)	—	—	—	—	—	—
	—	—	2	1.53	—	—
Non-productive:
Gulf Coast Basin	—	—	—	—	—	—
East Texas	—	—	—	—	—	—
Other (1)	—	—	—	—	—	—
	—	—	—	—	—	—
Total	—	—	2	1.53	—	—
Development:
Productive:
Gulf Coast Basin	—	—	—	—	—	—
East Texas	2	1.47	6	4.33	1	0.81
Other (1)	—	—	—	—	4	0.02
	2	1.47	6	4.33	5	0.83
Non-productive:
Gulf Coast Basin	—	—	—	—	—	—
East Texas	—	—	—	—	—	—
Other (1)	—	—	—	—	—	—
	—	—	—	—	—	—
Total	2	1.47	6	4.33	5	0.83

(1) Includes Oklahoma-Woodford.

At December 31, 2018, we had 3 gross (2.20 net) wells in progress.

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2018:

	Leasehold Acreage
	Developed		Undeveloped
	Gross	Net	Gross	Net
Louisiana	4,050	1,260	24,994	19,776
East Texas	42,843	21,746	11,310	6,725
Federal Waters	5,760	163	5,760	5,760
Total	52,653	23,169	42,064	32,261

Leases covering 1.5% of our net undeveloped acreage are scheduled to expire in 2019, 52% in 2020, 11% in 2021 and 35% thereafter. At December 31, 2018, we do not have any PUD reserves attributed to acreage that has a lease expiration date preceding the scheduled date for initial development. Of the minimal acreage subject to leases scheduled to expire during 2019, 100% relates to undeveloped acreage in East Texas.

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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.

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.

On August 8, 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. This comprehensive act contains many provisions that are 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.

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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 natural gas liquids ("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 handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act 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 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. 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.

To cover the various obligations of lessees on the Outer Continental Shelf (the “OCS”), the BOEM generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. While we were 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. As a result, we engaged a number of surety companies to post the requisite bonds. Pursuant to the terms of our agreements with these surety companies, we had provided cash deposits of $12.7 million as collateral to support certain of the bonds that are issued on our behalf. As a result of the sale of our Gulf of Mexico assets in January 2018, the majority of all cash deposits have been refunded as of the date hereof.

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.

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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 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 our operations, 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 handling 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.

Wastes, including hazardous wastes, are subject to regulation under the federal Resource Conservation and Recovery Act (“RCRA”) and state statutes. Much of the waste we generate in our operations, including hazardous waste, is exempt from regulation under RCRA, but generally remains subject to state storage, treatment and disposal requirements. The USEPA has limited the disposal options for certain hazardous wastes. It is possible that certain wastes generated by our oil and gas operations which are

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currently exempt from regulation under RCRA 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. Liable persons under CERCLA 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 the costs of such action from the responsible persons. 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. 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.

Discharges. The Clean Water Act (“CWA”) regulates the discharge of pollutants to Waters of the United States ("WOTUS"), including wetlands, and requires a permit for the discharge of pollutants, including petroleum, to such waters. The CWA also prohibits spills of oil and hazardous substances to WOTUS in excess of levels set by regulations and imposes liability in the event of a spill. 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 such waters. The CWA also requires a permit for the discharge of dredged or fill material into wetlands. A revised regulatory definition of WOTUS that would expand the applicability of CWA requirements was promulgated in 2015, but these regulations have since been subject to judicial challenges and administrative action resulting in uncertainties about the scope of the WOTUS definition. When the WOTUS definition is ultimately resolved, CWA obligations may be expanded. State laws further provide civil and criminal penalties and liabilities for spills to both surface and ground waters and require permits that set limits on discharges to such waters. We believe we are in substantial compliance with these requirements and that any noncompliance would not have a material adverse effect on us.

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 commissioned a study to identify potential risks associated with hydraulic fracturing and to improve scientific understanding to guide USEPA’s regulatory oversight, guidance and, where appropriate, rulemaking related to hydraulic fracturing. A final report for this study was released in December 2016 and provided information regarding potential vulnerability of drinking water resources to hydraulic fracturing, but did not reach conclusions regarding the frequency or severity of impacts due to data gaps and uncertainties. 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 Louisiana,

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which currently address hydraulic fracturing concerns by requiring disclosures of the content of fluids used in the process. 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 or 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. 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. We are not currently subjectto federal GHG permitting requirements, but regulation of GHG emissions is developing and highly controversial, and further regulatory, legislative and judicial developments may occur and 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 have been highly controversial, have been challenged, and their future is uncertain. While such requirements would be 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.

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 46,600 square feet of leased space, with an exploration office in The Woodlands, Texas in approximately 5,400 square feet 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.

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Employees

We had 54 full-time employees as of February 28, 2019. 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 on 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 as soon as reasonably practicable after such material is filed or furnished to the SEC. Information contained on or available through our website is not a part of or incorporated into this Form 10-K or any other report that we may file with or furnish to the SEC.

Item 1A. Risk Factors

Risks Related to Our Business, Industry and Strategy

Our Chapter 11 proceedings may have disrupted our business and may have materially and adversely affected our operations.

We have attempted to minimize the adverse effect of our Chapter 11 reorganization on our relationships with our employees, suppliers, customers and other parties. Nonetheless, our relationships with our customers, suppliers, certain liquidity providers, employees and other parties may have been adversely impacted and our operations, currently and going forward, could be materially and adversely affected.

Our Chapter 11 plan of reorganization (the "Plan") is based in large part upon assumptions and analyses developed by us. Our actual financial results may vary materially from the projections that we filed in connection with the Plan. If these assumptions and analyses prove to be incorrect, the Plan may be unsuccessful in its execution.

The Plan affects both our capital structure and the ownership, structure and operation of our business and reflects assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. In addition, the Plan relies upon financial projections, including with respect to revenue, EBITDA, capital expenditures, debt service and cash flow. The financial projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that were the basis of these financial forecasts will not be accurate. In our case, the forecasts were even more speculative than normal, because they involved fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by the Plan will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our business or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of the Plan.

Our historical financial information may not be indicative of our future financial performance.

On February 8, 2019, the effective date of our emergence from bankruptcy, we expect to adopt fresh start accounting and in accordance with the provisions of Financial Accounting Standards Board Accounting Standards Codification No. 852 - Reorganizations, we anticipate applying fresh start accounting in our financial statements commencing with our financial statements as of and for the quarterly period ended March 31, 2019. We expect that this will impact materially our 2019 operating results, as certain pre-bankruptcy debts were discharged in accordance with the Plan immediately prior to our emergence from bankruptcy, and our assets and liabilities were adjusted to their fair values upon emergence. Accordingly, our financial condition and results of operations following our emergence from Chapter 11 will not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, as a result of the implementation of the Plan and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance.

Upon our emergence from bankruptcy, the composition of our board of directors changed significantly.

Under the Plan, the composition of our board of directors changed significantly. All of our board members, other than Charles T. Goodson, are new to the Company. Our new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

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The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. Our operations are dependent upon a diverse group of key senior management. In addition, we employ numerous other skilled technical personnel, including geologists, geophysicists and engineers that are essential to our operations. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

The carrying value of our oil and natural gas assets is expected to be restated under fresh start accounting upon our emergence from bankruptcy. The restated amount could exceed the full cost ceiling limit at March 31, 2019, which would result in a ceiling test write-down.

As a result of our reorganization under Chapter 11 and subsequent emergence from bankruptcy on February 8, 2019, we expect to apply fresh start accounting to our balance sheet which results in the carrying value of our oil and natural gas properties being restated based on their fair value. We are still in the process of estimating the fair value. It is possible that our estimate of the fair value of our oil and natural gas properties utilized as the fresh start opening balance upon our emergence from bankruptcy could result in the carrying value exceeding the full cost ceiling limit at March 31, 2019, which would require us to record a ceiling test write-down.

Oil and natural gas prices are volatile and an extended decline in the prices of oil and natural gas would likely have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations 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. 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;

• the level of global exploration and production;

• the level of global inventories;

• market uncertainty;

• the level of consumer product demand;

• prevailing prices on local price indices in the areas in which we operate;

• the proximity, capacity, cost and availability of gathering and transportation facilities;

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

• technological advances affecting energy companies;

• 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, Africa, South America and Russia;

• the effect of worldwide energy conservation and environmental protection efforts;

• shareholder activism and activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas so as to minimize emissions of greenhouse gas;

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

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• the price and availability of alternate energy sources.

We cannot predict future oil and natural gas prices and such prices may decline further. The extended decline in oil and natural gas prices has, and may continue to, adversely affect our financial condition, liquidity, ability to meet our financial obligations 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 has required and may require us to record additional ceiling test write-downs and may cause our estimated proved reserves at December 31, 2019 to decline compared to our estimated proved reserves at December 31, 2018. 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; however in the current commodity price market, our ability to enter into effective hedging transactions may be limited. We cannot assure you that we can enter into effective hedging transactions in the future or 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, remain in compliance with debt covenants and make payments on our debt.

The aggregate principal amount of our outstanding indebtedness as of February 8, 2019 is $130 million. We currently have no additional availability under the Exit Facility. We may incur additional indebtedness in the future. 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 amounts borrowed under the Exit Facility and our 2024 PIK 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 portion of our cash flows to pay interest on our debt, including approximately $3.9 million in 2019 for interest on amounts borrowed under the Exit Facility, which will reduce the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or other business activities;

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

• our 2024 PIK Notes will increase our debt level at each semi-annual interest payment date if we elect not to pay the interest in cash;

• 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 amounts borrowed under the Exit Facility, 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 amounts borrowed under the Exit Facility, 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 amounts borrowed under the Exit Facility, 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.

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We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us in an amount sufficient to enable us to pay principal and interest on our indebtedness, including amounts borrowed under the Exit Facility, 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 amounts borrowed under the Exit Facility, 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.

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.

Our failure to comply with a significant financial ratio under the Exit Facility may require us to repay borrowings or be in default thereunder.

Under the terms of the Exit Facility, we may not permit or allow the ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of our oil and gas properties, before any state, federal, foreign or other income taxes, attributable to total proved reserves, using three-year strip prices then in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the aggregate outstanding principal amount of the term loans thereunder to be less than 1.5 to 1.0 as measured on the last day of each calendar quarter. We may not be able to comply with this restrictive financial ratio in the future and, as a result, we may either (i) prepay the outstanding term loans such that after giving effect to such prepayment, the financial covenant is met or (ii) be in default under the Exit Facility, in which case the term loans and all other amounts owed pursuant to the Exit Facility would become immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow funds sufficient to refinance it. An event of default under the Exit Facility, if not cured or waived, could result in an event of default under the 2024 PIK Notes.

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.

The Exit Facility and the indenture governing our 2024 PIK 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;

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• enter into certain transactions with affiliates;

• create or assume certain liens on our assets;

• enter into sale and leaseback transactions;

• merge or 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, the Exit Facility requires 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.

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 the Exit Facility and the indenture governing our 2024 PIK 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 the Exit Facility and the 2024 PIK Notes. A default, if not cured or waived, could result in all indebtedness outstanding under the Exit Facility and the 2024 PIK 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.

We may be able to incur substantially more debt, which could exacerbate the risks associated with our indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. Although covenants under the Exit Facility and the indenture governing our 2024 PIK Notes will limit our ability to incur additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be significant. Our 2024 PIK Notes will increase our debt level at each semi-annual interest payment date if we elect not to pay the interest in cash.

If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify. Any of these risks could result in a material adverse effect on our business, financial condition, results of operations, business prospects and ability to satisfy our obligations under our outstanding indebtedness.

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 or other 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. 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 be responsible for offshore decommissioning liabilities for offshore interests we no longer own.

Under state and federal law, oil and gas companies are obligated to plug and abandon a well and restore the lease to pre-operating conditions after operations cease. Federal regulations allow in certain circumstances the government to call upon predecessors in interest of oil and gas leases to pay for plugging and abandonment, restoration and decommissioning obligations if the current operator fails to fulfill those obligations, which can be very significant. In January 2018, we completed a strategic shift from offshore Gulf of Mexico operations to onshore operations when we sold our remaining Gulf of Mexico assets. In connection with the divestiture of our Gulf of Mexico assets, we entered into various arrangements with the purchasers whereby the purchasers assumed our plugging and abandonment liabilities and other liabilities related to decommissioning such Gulf of Mexico assets. If purchasers of our former Gulf of Mexico assets, or any successor owners of those assets, are unable to meet their

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plugging and abandonment and other decommissioning obligations due to bankruptcy, dissolution or other related liquidity issues, we may be unable to rely on our arrangements with them to fulfill (or provide reimbursement for) those obligations. In those circumstances, the Federal government may seek to impose the purchasers' or other successors' plugging and abandonment obligations on us and any other predecessors in interest. Such payments could be significant and adversely affect our business, results of operations, financial condition and cash flows.

Moreover, recent changes to the BOEM’s supplemental bonding requirements have the potential to adversely impact the financial condition of operators in the Gulf of Mexico and increase the number of operators seeking bankruptcy protection, given the current pricing of commodities. In July 2016, BOEM issued a Notice to Lessees and Operators (NTL) that augments requirements for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The NTL, which became effective in September 2016, eliminates the agency’s past practice of waiving supplemental bonding obligations where a company could demonstrate a certain level of financial strength. Instead, BOEM will allow companies to "self-insure," but only up to 10% of a company’s "tangible net worth," which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets.

The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations, and the agency continues to negotiate with offshore operators to post additional financial assurance and develop tailored plans to meet BOEM’s revised estimates for offshore decommissioning obligations. Projected decommissioning costs of operations in the Gulf of Mexico continue to increase, and the volatile price of oil and gas has adversely affected the net worth of many operators. BOEM’s revisions to its supplemental bonding process could result in demands for the posting of increased financial assurance by the entities to whom we divested our Gulf of Mexico assets as well as other operators in the Gulf of Mexico. This will force operators to obtain surety bonds or other forms of financial assurance, the costs of which could be significant. Moreover, BOEM’s NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which will in turn force these operators to seek additional surety bonds and could, consequently, exceed the surety bond market’s ability to provide such additional financial assurance. Operators who have already leveraged their assets as a result of the volatile commodities market could face difficulty obtaining surety bonds because of concerns the surety may have about the priority of their lien on the operators' collateral. Consequently, BOEM’s changes could result in additional operators in the Gulf of Mexico initiating bankruptcy proceedings, which in turn could result in the government seeking to impose plugging and abandonment costs on predecessors in interest in the event that the current operator cannot meet its plugging and abandonment obligations. As a result, we could find ourselves liable to pay for the plugging and abandonment costs of any entity we divested our Gulf of Mexico assets to, which payments could be significant and adversely affect our business, results of operations, financial condition and cash flows.

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 44% 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 44% 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, 2018 approximately 44% of our production and approximately 6% of our estimated proved reserves are located 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 past storms including Hurricanes Katrina, Rita, Gustav and Ike. In addition, according to certain scientific studies, emissions of carbon dioxide, 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

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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.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Approximately 58% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

As of December 31, 2018, approximately 58% of our net leasehold acreage was undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

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. However, our 2018 production, excluding the impact of asset sales and the results from successful

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exploration wells which are not included in the prior year reserve report, was approximately 14%lower than amounts projected in our 2017 reserve report. We cannot assure you that these differences will not again be material in the future.

Approximately 53% of our estimated proved reserves at December 31, 2018 are undeveloped and 1% 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 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, 2018 are based on twelve-month, first day of 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 may 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 Exit Facility and the indenture governing our 2024 PIK Notes contain 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.

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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 twelve-month, first day of month, average price of oil and natural gas 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 recognize further write downs of 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. We did not incur a ceiling test write-down during the years ended December 31, 2018 and December 31, 2017. See the risk factor "The carrying value of our oil and natural gas assets is expected to be restated under fresh start accounting upon our emergence from bankruptcy. The restated amount could exceed the full cost ceiling limit at March 31, 2019, which would result in a ceiling test write-down" above for a discussion regarding the possible effect fresh start accounting could have on our potential to record a ceiling-test writedown in the first quarter of 2019.

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 energy 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.

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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, further regulation of the technique under various federal and state authorities. A number of states, including Louisiana and Texas, have required operators or service companies to disclose chemical components in fluids used for hydraulic fracturing and some states have imposed bans or moratoria on new natural gas development or the use of hydraulic fracturing. Further regulation may include, among other things, additional permitting requirements, enhanced reporting obligations, and stricter standards for discharges and emissions associated with gas production, storage and transport. The future of such regulation is controversial and uncertain. Such requirements, if imposed, would be expected to increase the cost of natural gas production.

Recent seismic events have been observed in some areas (including 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 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. 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 any additional federal, state or local legislation or regulation regarding hydraulic fracturing, management of drilling fluids, stricter emission standards, well integrity requirements or climate change, 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.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which was passed by the U.S. Congress and signed into law in July 2010, provides for statutory and regulatory requirements for derivative transactions, including crude oil and natural gas derivative transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The Dodd-Frank Act requires Commodities Futures and Trading Commission, (the “CFTC”), and the SEC and other regulators to promulgate rules and regulations implementing the Dodd-Frank Act. The CFTC has re-proposed 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, the impact of those provisions on us is uncertain at this time.

It is not possible at this time to predict with certainty the full effect of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act may require us to comply with margin requirements and with certain clearing and trade-execution requirements if we do not satisfy certain specific exceptions. Although we expect to qualify for the end-user exception to the clearing, trade execution and margin requirements for swaps entered to hedge our commodity risks, the application of the requirements to other market participants, such as swap dealers, may change the cost and availability of our derivatives. Depending on the rules adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities derivative transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could therefore reduce our ability to execute transactions to reduce commodity price risk and thus protect cash flows.

The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until all of the regulations are implemented. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading

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in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Although none of these changes were included in the Tax Cuts and Jobs Act, future adverse changes could include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, 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 Gulf Coast Basin 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.

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;

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• 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.

Stricter requirements and standards may be imposed in future environmental legislation and regulation. Our drilling plans may be affected as a result of new or modified environmental requirements. 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.

Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.

As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information, to misappropriate financial assets or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of financial assets, sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely affecting our financial condition and results of operations.

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.

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We are and may in the future be involved in legal proceedings that could result in substantial liabilities.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.    

Risks Relating to Our Outstanding Common Stock

There may be circumstances in which the interests of two groups of our stockholders could be in conflict with the interests of our other stockholders.

Two groups of our stockholders advised by two investment management firms currently hold approximately 44% and 28%, respectively, of our post-reorganization Class A Common Stock. Circumstances may arise in which these groups of stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our Class A Common Stock. Furthermore, pursuant to the Successor’s amended and restated certificate of incorporation, each of these two groups of stockholders has the right to elect two directors to our Board of Directors for so long as each such group holds at least 20% of the then-outstanding Class A Common Stock or one director to our Board of Directors for so long as each such group holds at least 10% but less than 20% of the then-outstanding Class A Common Stock. As a result such directors will control decisions made by our Board of Directors, including whether to enter into the transactions described above.

In addition, our significant concentration of share ownership may adversely affect the trading price of our Class A Common Stock because investors may perceive disadvantages in owning shares in companies with significant stockholders.

There is no meaningful trading market for our Class A Common Stock and the market price of our Class A Common Stock is subject to volatility, which could make it difficult for you to sell your Class A Common Stock.

Upon our emergence from bankruptcy, the Predecessor’s common stock was canceled and the Successor issued new Class A Common Stock. The Class A Common Stock is not currently traded on a national securities exchange and no broker dealer is making an active market in the Class A Common Stock. Although our Class A Common Stock is eligible to trade in the "Grey Market" under the symbol "QWST", as of the date hereof, no trades have been reported on the www.otcmarkets.com website since the Effective Date. According to the www.otcmarkets.com website, "Grey Market" describes securities that are not currently traded on the OTCQX, OTCQB or Pink markets and broker-dealers are not willing or able to publicly quote these securities because of a lack of investor interest, company information availability or regulatory compliance. Accordingly, even if a trading market develops for our Class A Common Stock, the market price of our Class A Common Stock could be subject to wide fluctuations in response to, and the level of trading that develops with our Class A Common Stock may be affected by, numerous factors beyond our control such as our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our Class A Common Stock, the lack of comparable historical financial information due to our expected adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Form 10-K. No assurance can be given that an active market will develop for our Class A Common Stock or as to the liquidity of the trading market for our Class A Common Stock. Our Class A Common Stock may be traded only infrequently, and reliable market quotations may not be available. Holders of our Class A Common Stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our Class A Common Stock, or the expectation of these sales, could materially and adversely affect the market price of our Class A Common Stock. For so long as our Class A Common Stock is not listed on a national securities exchange, our ability to access equity markets, obtain financing and provide equity incentives could be negatively impaired.

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, among other things, those that:

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• permit two groups of our stockholders to elect up to four members of our board of directors and limit the removal of such directors;

• authorize our Board of Directors to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;

• establish advance notice procedures for nominating directors or presenting matters at stockholder meetings;

• prohibit cumulative voting; and

• restrict certain transfers (including acquisitions and dispositions) of the Company’s securities to assist in the preservation of the Company’s ability to utilize its current and future tax benefits.

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 Exit Facility and the indenture governing the 2024 PIK Notes. Any future dividends also may be restricted by our then-existing debt agreements.

Item 1B Unresolved Staff Comments

None

Item 3. Legal Proceedings

The Company 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. Although we cannot predict the outcome of these proceedings with certainty, management believes that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material adverse effect on the Company's business or financial position.

On October 11, 2016, PQ LLC and another exploration and production company were named as defendants in a putative class action lawsuit filed on behalf of royalty owners in the state district court in Hughes County, Oklahoma. The lawsuit alleges that PQ LLC and the other defendant failed to pay interest with respect to untimely royalty payments. On November 28, 2016, the Company removed the lawsuit to the U.S. District Court for the Eastern District of Oklahoma.

On October 25, 2016, PQ LLC and another exploration and production company were named as defendants in a putative class action lawsuit filed on behalf of royalty owners in the U.S. District Court for the Eastern District of Oklahoma. The lawsuit alleges that PQ LLC and the other defendant underpaid royalties or did not pay royalties by various means.

On November 6, 2018, the Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On January 31, 2019, the Bankruptcy Court entered an order confirming the Plan under Chapter 11 of the Bankruptcy Code. On February 8, 2019, the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases. For more information regarding the bankruptcy, see “Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code” in Items 1 and 2. “Business and Properties” of this Form 10-K above.

Commencement of the Chapter 11 Cases automatically stayed the lawsuits noted above as well as other claims and actions that were or could have been brought prior to November 6, 2018. Under the Plan, the aggregate portion of the $1.2 million fund set aside for general unsecured claims under the Plan (the “General Unsecured Claims Distribution”) that may be distributed to the holders of claims related to the lawsuits noted above is not permitted to exceed $400,000.

On February 8, 2019, Dacarba LLC was appointed as the GUC Administrator pursuant to the Plan. The GUC Administrator is responsible for, among other things, (i) objecting to general unsecured claims, (ii) administering the general unsecured claims allowance process, and (iii) authorizing distributions to holders of the general unsecured claims from the General Unsecured Claims Distribution, including the claims related to the lawsuits noted above. There are in excess of 300 remaining general unsecured claims subject to the Bankruptcy Court’s jurisdiction.

The Reorganized Debtors are responsible for the administering the priority, administrative expense, and secured claims. There are in excess of 100 remaining priority, administrative expense, and secured claims subject to the Bankruptcy Court’s jurisdiction. The claims administration process is ongoing and it is uncertain when the total allowed claims pool will be determined.

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Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

Item 5.     Market Price of and Dividends on Common Stock

From May 7, 2018 through February 8, 2019, the Predecessor’s shares of common stock were listed on the OTCQX market under the symbol “PQUE.” Prior to May 7, 2018, the Predecessor’s shares of common stock were listed on the New York Stock Exchange under the symbol “PQ.”

In connection with our emergence from bankruptcy, on the Effective Date, the Predecessor’s shares of common stock were canceled and ceased to be listed on the OTCQX market. Simultaneous with the cancellation of the Predecessor’s shares of common stock, the Successor authorized for issuance 64,999,998 shares of Class A Common Stock, one share of Class B Common Stock, one share of Class C Common Stock and 10,000,000 shares of preferred stock, and the Successor issued 8,900,000 shares of Class A Common Stock pro rata to the holders of the Old Notes. In addition, pursuant to the terms of the Plan, the Successor issued 300,000 shares of Class A Common Stock to certain holders of the Old Notes for their commitment to backstop the Exit Facility, one share of Class B Common Stock to the Class B Holder (as defined in the Successor’s amended and restated certificate of incorporation), and one share of Class C Common Stock to the Class C Holder (as defined in the Successor’s amended and restated certificate of incorporation).

The Class A Common Stock is not currently traded on a national securities exchange and no broker dealer is making an active market in the Class A Common Stock. Although our Class A Common Stock is eligible to trade in the “Grey Market” under the symbol “QWST”, as of the date hereof, no trades have been reported on the www.otcmarkets.com website since the Effective Date. According to the www.otcmarkets.com website, “Grey Market” describes securities that are not currently traded on the OTCQX, OTCQB or Pink markets and broker-dealers are not willing or able to publicly quote these securities because of a lack of investor interest, company information availability or regulatory compliance. Information contained in or available through the www.otcmarkets.com website is not part of or incorporated into this Form 10-K or any other report that we may file with or furnish to the SEC. There is currently no established public trading market for the shares of Class B Common Stock and Class C Common Stock and there has not been an established public trading market for the shares of Class B Common Stock and Class C Common Stock since the Company emerged from bankruptcy on the Effective Date. As of March 22, 2019, there were approximately forty, three and one shareholders of record for the Class A Common Stock, Class B Common Stock and Class C Common Stock, respectively.

We have never paid a dividend on the Predecessor's shares of common stock or the Successor's shares of Class A Common Stock, Class B Common Stock and Class C Common Stock, cash or otherwise, and intend to retain our cash flow from operations for the future operation and development of our business. 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 and subject to any restrictions under our indebtedness. 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.”    

There were no repurchases of the Predecessor's common stock during the quarter ended December 31, 2018. 

Item 6.    Selected Financial Data

Not Applicable.

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Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with primary operations in Texas and Louisiana. 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 with our acquisition of the Carthage Field in East Texas. From 2005 through 2015, we further implemented this strategy by focusing our efforts in the Woodford Shale play in Oklahoma. In response to lower commodity prices and to strengthen our balance sheet, we sold all of our Oklahoma assets in three transactions that closed in June 2015, April 2016 and October 2016. In December 2017, we acquired approximately 24,600 gross acres in central Louisiana targeting the Austin Chalk to attempt to increase our oil production and reserves. During January 2018, we sold all of our Gulf of Mexico assets to further reduce our liabilities and strengthen our liquidity position.

Our liquidity position has been negatively impacted by lower commodity prices beginning in 2014. In response to the lower commodity prices, we executed numerous actions beginning in 2015 aimed at increasing liquidity, reducing overall debt levels and other liabilities and extending debt maturities. Despite these actions, our overall liquidity position and our cash available for capital expenditures continued to be negatively impacted by weak natural gas prices, declining production and increased cash interest expense on outstanding indebtedness.

As a result of the forgoing, we engaged in discussions and negotiations with the lenders under the Multidraw Term Loan Agreement (as defined below), certain holders of the 2021 Notes (as defined below) and 2021 PIK Notes (as defined below) and their legal and financial advisors regarding various alternatives with respect to our capital structure and financial position, including the significant amount of indebtedness, and the August 15, 2018 interest payments overdue on our 2021 Notes and 2021 PIK Notes.

Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

As a result of the forgoing discussions and negotiations, on November 6, 2018 (the “Petition Date”), we and our wholly-owned direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions (collectively, the “Petition,” and the cases commenced thereby, the “Chapter 11 Cases”) seeking relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).

In connection with the Chapter 11 filing, on the Petition Date, the Debtors entered into a restructuring support agreement (the “Restructuring Support Agreement”) with (i) holders of 81.83% of our 10% Second Lien Senior Secured Notes due 2021 (the “2021 Notes”), (ii) holders of 84.76% of our 10% Second Lien Senior Secured PIK Notes due 2021 (the “2021 PIK Notes”) and (iii) each of the lenders, or investment advisors or managers for the account of each of the lenders under our multi-draw term loan agreement (the “Multidraw Term Loan Agreement”), pursuant to which such parties agreed to support the Plan (as defined below).

On January 31, 2019, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Debtors’ First Amended Chapter 11 Plan of Reorganization, as Immaterially Modified as of January 28, 2019 (as amended, modified or supplemented from time to time, the “Plan”) under Chapter 11 of the Bankruptcy Code. On February 8, 2019 (the “Effective Date”), the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases. On the Effective Date, TDC Energy, LLC, Pittrans, Inc. and Sea Harvester Energy Development, L.L.C. were dissolved. The remaining Debtors (collectively, the “Reorganized Debtors”) continue in existence. In this Form 10-K, we may refer to the Company prior to the Effective Date as the “Predecessor,” and on and after the Effective Date as the “Successor.”

On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Company:

• Adopted an amended and restated certificate of incorporation and bylaws;

• Appointed four new members to the Successor’s board of directors to replace all of the directors of the Predecessor, other than the director also serving as Chief Executive Officer, who was re-appointed pursuant to the Plan;

• Canceled all of the Predecessor’s common stock and 6.875% Series B Cumulative Convertible Perpetual Preferred Stock with the former holders thereof not receiving any consideration in respect of such stock;

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• Issued to the former holders of the Predecessor’s 2021 Notes and 2021 PIK Notes (collectively, the “Old Notes”), in exchange for the cancellation and discharge of the Old Notes:

◦ 8,900,000 shares of the Successor’s Class A Common Stock; and

◦ $80.0 million of the Successor’s 10% Senior Secured PIK Notes due 2024 (the “2024 PIK Notes”);

• Issued 300,000 shares of the Successor’s Class A Common Stock to certain former holders of the Old Notes for their commitment to backstop the Exit Facility (as defined below);

• Issued to the Class B Holder (as defined in the Successor’s amended and restated certificate of incorporation) one share of the Successor’s Class B Common Stock, which confers certain rights to elect directors and certain drag-along rights;

• Issued to the Class C Holder (as defined in the Successor’s amended and restated certificate of incorporation) one share of the Successor’s Class C Common Stock, which confers certain rights to elect directors and certain drag-along rights;

• Entered into a new $50 million senior secured Term Loan Agreement (the “Exit Facility”) upon the repayment and termination of the Predecessor’s Multidraw Term Loan Agreement;

• Entered into a registration rights agreement (the “Registration Rights Agreement”) with certain holders of the Successor’s Class A Common Stock and 2024 PIK Notes; and

• Adopted a new management incentive plan (the “2019 Long Term Incentive Plan”) for officers, directors and employees of the Successor and its subsidiaries, pursuant to which 1,344,000 shares of the Successor’s Class A Common Stock were reserved for issuance.

The foregoing is a summary of the substantive provisions of the Plan and related transactions and is not intended to be a complete description of, or a substitute for a full and complete reading of the Plan and the other documents referred to above. See “Note 2- Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” in Item 8. Financial Statements and Supplementary Data of this Form 10-K for a discussion of our bankruptcy and resulting reorganization.

Bankruptcy Accounting and Financial Reporting

The consolidated financial statements have been prepared in accordance with ASC 852, Reorganizations, for the period subsequent to the bankruptcy filing. ASC 852 requires that the consolidated financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the Chapter 11 Cases are recorded as reorganization items on the consolidated statement of operations. In addition, the pre-petition obligations that may be impacted by the bankruptcy reorganization process are classified on the consolidated balance sheet as liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

Debtor-In-Possession

During the pendency of the Chapter 11 Cases, the Debtors operated as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. In general, as debtors-in-possession under the Bankruptcy Code, the Debtors were authorized to continue to operate as an ongoing business, but were not permitted to engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court. Pursuant to motions filed with the Bankruptcy Court that were designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, customers and employees, the Bankruptcy Court authorized the Debtors to conduct their business activities in the ordinary course, including, among other things and subject to the terms and conditions of such orders, authorizing the Debtors to: (i) pay employees' wages and related obligations; (ii) continue to operate their cash management system in a form substantially similar to pre-petition practice; (iii) continue to honor certain obligations related to our royalty obligations; and (iv) pay taxes in the ordinary course.

Reorganization Items

The Debtors have incurred costs associated with the reorganization, primarily legal and professional fees. In accordance with applicable guidance, costs associated with the bankruptcy proceedings have been recorded as reorganization items within the accompanying consolidated statement of operations for the year ended December 31, 2018. Reorganization items included $3.8 million related to post petition professional fees and $0.5 million related to claims relating to the Chapter 11 Cases and adjustments to the carrying value of debt classified as liabilities subject to compromise.

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Liabilities Subject to Compromise

The accompanying consolidated balance sheet as of December 31, 2018 includes amounts classified as liabilities subject to compromise, which represent liabilities which have been allowed as claims in the Chapter 11 Cases. These amounts represent the Debtors' current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process.

Liabilities subject to compromise at December 31, 2018 consisted of the following (in thousands):            

	December 31, 2018
10% Senior PIK Notes due 2021	$	275,046
10% Senior Notes due 2021	9,427
Accrued interest	20,624
Accounts payable to vendors	874
Other long-term liabilities	510
Other accrued liabilities	2,724
Preferred stock dividend payable	14,649
Liabilities subject to compromise	$	323,854

Critical Accounting Policies

Bankruptcy Accounting

For the year ended December 31, 2018, the consolidated financial statements have been prepared in accordance with Accounting Standards Codification ("ASC") 852, Reorganizations. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the Chapter 11 Cases will be recorded in a reorganization line item on the consolidated statements of operations. In addition, the pre-petition obligations that have been impacted by the bankruptcy reorganization process will be classified on the balance sheet in liabilities subject to compromise. These liabilities will be reported at the amounts allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See "Note 2 - Voluntary Reorganization under Chapter 11 of the Bankruptcy Code" in Item 8 for a full disclosure of accounting methods utilized in this Form 10-K.

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 No. 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

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reserves estimates. Pricing is based on a 12-month, first day of month, average price 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 in the ceiling test calculation 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 unevaluated 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.

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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.

	Year Ended December 31,
	2018		2017
Production:
Oil (Bbls)	325,948		591,558
Gas (Mcf)	16,012,892		19,610,964
Ngl (Mcfe)	3,366,389		4,452,817
Total Production (Mcfe)	21,334,969		27,613,129
Sales:
Total oil sales	$	21,027,470	$	31,258,109
Total gas sales	50,768,159		60,922,072
Total ngl sales	15,303,178		16,107,068
Total oil and gas sales	$	87,098,807	$	108,287,249
Average sales prices:
Oil (per Bbl)	$	64.51	$	52.84
Gas (per Mcf)	3.17		3.11
Ngl (per Mcfe)	4.55		3.62
Per Mcfe	4.08		3.92

The above sales and average sales prices include increases to revenue related to the settlement of gas hedges of $805,000 and $1,461,000, for the years ended December 31, 2018 and 2017, respectively. The above sales and average sales prices include decreases to revenue related to the settlement of oil hedges of $1,428,000 for the year ended December 31, 2018. There were no settlements of oil hedges for the years ended December 31, 2017 and no settlements of ngl hedges for any period presented.

Comparison of Results of Operations for the Years Ended December 31, 2018 and 2017

In January 2018, we completed the sale of our Gulf of Mexico assets. During the year ended December 31, 2017, these assets contributed the following to our oil and gas operations:

	Year ended		Percent of Total
	December 31, 2017		Company
Production:
Oil (Bbls)	304,384		51	%
Gas (Mcf)	4,644,749		24	%
Ngl (Mcfe)	466,608		10	%
Total Production (Mcfe)	6,937,661		25	%
Sales:
Total oil sales	$	16,021,023	51	%
Total gas sales	14,135,290		23	%
Total ngl sales	1,821,102		11	%
Total oil and gas sales	$	31,977,415	30	%

Net loss available to common stockholders totaled $13,919,000 and $11,776,000 for the years ended December 31, 2018 and 2017, respectively. The primary fluctuations were as follows:

Production Total production decreased 23% during the year ended December 31, 2018 as compared to the 2017 period. The decrease in production was due primarily to the sale of our Gulf of Mexico assets in January 2018 and normal production declines at our legacy Gulf Coast and East Texas fields. Partially offsetting these decreases were increases as a result of the success of our East Texas drilling program.

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Gas production during the year ended December 31, 2018decreased 18% from the 2017 period. The decrease in gas production was due to the sale of our Gulf of Mexico assets and normal production declines at our legacy Gulf Coast and East Texas fields. Partially offsetting these decreases were increases as a result of our successful East Texas drilling program and the successful recompletion of our Thunder Bayou well. We expect our 2019 average daily gas production to approximate the average daily gas production realized during 2018.

Oil production during the year ended December 31, 2018decreased 45% as compared to the 2017 period as a result of the January 2018 sale of our Gulf of Mexico assets and the sale of our E. Lake Verret field during the second quarter of 2017. Partially offsetting this decrease was an increase as a result of the successful recompletion of our Thunder Bayou well and our successful East Texas drilling program. We expect our 2019 average daily oil production to approximate the average daily oil production realized during 2018.

Ngl production during the year ended December 31, 2018decreased 24% from the 2017 period primarily as a result of the sale of our Gulf of Mexico assets and normal production declines at our legacy Gulf Coast and East Texas fields. These decreases were partially offset by the successful recompletion of our Thunder Bayou well during the first quarter of 2017 and our successful drilling program in East Texas. We expect our 2019 average daily Ngl production to approximate the average daily Ngl production realized during 2018.

Prices Including the effects of our hedges, average gas prices per Mcf for the year ended December 31, 2018 were $3.17 as compared to $3.11 for the 2017 period. Average oil prices per Bbl for the year ended December 31, 2018 were $64.51 as compared to $52.84 for the 2017 period and average Ngl prices per Mcfe were $4.55 for the year ended December 31, 2018, as compared to $3.62 for the 2017 period. Stated on an Mcfe basis, unit prices received during the year ended December 31, 2018 were 4%higher than the prices received during the 2017 period.

Revenue Including the effects of hedges, oil and gas sales during the twelve months endedDecember 31, 2018decreased 20% to $87,099,000, as compared to oil and gas sales of $108,287,000 during the 2017 period. This decrease was primarily the result of the above mentioned production decreases as a result of the sale of our Gulf of Mexico assets.

Expenses Lease operating expenses for the year ended December 31, 2018 totaled $20,552,000, or $0.96 per Mcfe, as compared to $33,162,000, or $1.20 per Mcfe, during the 2017 period. The decreases in total and per unit lease operating expenses for the year ended December 31, 2018 are primarily a result of the divestiture of our Gulf of Mexico wells which had a higher per unit rate as compared to our remaining East Texas and South Louisiana wells. We expect per unit lease operating expenses during 2019 to approximate those realized during 2018.

Production taxes for the year ended December 31, 2018 totaled $3,198,000, or $0.15 per Mcfe, as compared to $3,302,000, or $0.12 per Mcfe, during the 2017 period.

General and administrative expenses during the year ended December 31, 2018 totaled $17,564,000 as compared to $15,860,000 during the 2017 period. General and administrative expenses increased 11% during the year ended December 31, 2018 primarily due to the inclusion of $4,401,000 of costs related to pre-petition professional fees related to our bankruptcy filing.  Included in general and administrative expenses for 2018 are share-based compensation costs, net of amounts capitalized, of $828,000, compared to $1,546,000 during the 2017 period. We capitalized $6,300,000 of general and administrative costs during the year ended December 31, 2018 as compared to $7,011,000 during the comparable 2017 period.

Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the year ended December 31, 2018 totaled $22,410,000, or $1.05 per Mcfe, as compared to $31,667,000, or $1.15 per Mcfe, during the comparable 2017 period. The decrease in the per unit DD&A rate is primarily the result of the divestiture of our Gulf of Mexico assets in January 2018 and the sale of our East Texas saltwater assets during the fourth quarter of 2017. We expect our 2019 DD&A rate to approximate 2018.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $28,147,000 during the year ended December 31, 2018, as compared to $28,836,000 during 2017. During the year ended December 31, 2018, our capitalized interest totaled $1,836,000 as compared to $1,571,000 during the 2017 period. Interest expense during the year ended December 31, 2018 included the write off in September 2018 of the remaining deferred financing costs related to our Old Loan Agreement (as defined below) in the amount of $1,635,000. We expect interest expense to be significantly reduced during 2019 as result of the bankruptcy filing and related change to our debt as discussed below.

The consolidated financial statements have been prepared in accordance with ASC 852, Reorganizations, for the period subsequent to the bankruptcy filing. ASC 852 requires that the consolidated financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, costs associated with the bankruptcy proceedings have been recorded as reorganization items on the consolidated statement of operations. Reorganization items included $3,760,000 related to post-petition professional fees and $534,000 related to adjustments to certain claims relating to the Chapter 11 Cases and to the carrying value of debt classified as liabilities subject to compromise.

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Income tax expense during the year ended December 31, 2018 totaled $152,000, as compared to an income tax benefit of $949,000 during the 2017 period. We typically provide for income taxes at the statutory federal income tax rate 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 in 2016 and prior years, we have incurred a three-year cumulative 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 $118,716,000 as of December 31, 2018.

The Tax Cuts and Jobs Act (the “Act”) was enacted on December 22, 2017. We made a reasonable estimate of the effects on existing deferred tax balances and recognized a provisional amount of approximately $64.9 million as of December 31, 2017 to remeasure deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. We finalized our accounting for the Act in connection with the filing of our 2017 federal tax return and determined no adjustment was necessary to the previously recognized provisional amount.

Liquidity and Capital Resources

At December 31, 2018 we had working capital of approximately $29.2 million compared to a working capital deficit of approximately $5.9 million at December 31, 2017. We have historically financed our acquisition, exploration and development activities principally through cash flow from operations, borrowings from banks and other lenders, issuances of equity and debt securities, joint ventures and sales of assets. However, our liquidity position has been negatively impacted by lower commodity prices beginning in 2014. In response to lower commodity prices we executed a number of transactions aimed at increasing liquidity, reducing overall debt levels and other liabilities and extending debt maturities. Despite such actions, our overall liquidity position and our cash available for capital expenditures continued to be negatively impacted by weak natural gas prices, declining production and increasing cash interest expense on outstanding indebtedness.

As a result of the forgoing, we engaged in discussions and negotiations with the lenders under the Multidraw Term Loan Agreement, certain holders of the Company’s 2021 Notes and 2021 PIK Notes, and their legal and financial advisors regarding various alternatives with respect to our capital structure and financial position, including the significant amount of indebtedness, and the August 15, 2018 interest payments overdue on our 2021 Notes and 2021 PIK Notes. As a result of the forgoing discussions and negotiations, on November 6, 2018, we and our direct and indirect subsidiaries filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. See "Overview - Voluntary Reorganization under Chapter 11 of the Bankruptcy Code" above for more information. Since the Chapter 11 filings on November 6, 2018, our principal sources of liquidity have been limited to cash flow from operations and cash on hand. We are pursuing various alternatives to increase our liquidity, including joint ventures and asset sales. In addition to the cash requirements necessary to fund ongoing operations, we have incurred and continue to incur significant professional fees and other costs in connection with our bankruptcy filing and administration of the Chapter 11 Cases. See "Item 1A Risk Factors".

Source of Capital: Operations

Net cash flow provided by operations decreased from $44.2 million during the year ended December 31, 2017 to $18.8 million during the 2018 period. The decrease in operating cash flow during 2018 as compared to 2017 was primarily attributable to reductions in our accounts payable to vendors, the sale of our Gulf of Mexico assets and the professional fees incurred in connection with our bankruptcy filing and administration of the Chapter 11 Cases.

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 pursuing a joint venture in our East Texas assets aimed at bringing in liquidity and reducing our share of drilling capital. We cannot assure you that we will be able to sell any of our assets or consummate additional joint ventures in the future.

On January 31, 2018, we sold our Gulf of Mexico properties. Although we received no cash proceeds from the sale of these properties and were required to contribute approximately $3.8 million toward future abandonment costs, we will no longer have an obligation for $35.1 million of estimated undiscounted future abandonment costs related to the properties sold. Additionally, we received refunds as of the date hereof of $12.4 million related to a depositary account that served to collateralize a portion of our offshore bonds related to these properties.

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Source of Capital: Debt

Pre-emergence Indebtedness

On August 19, 2010, we issued $150 million in principal amount of our 10% Senior Notes due 2017. On July 3, 2013, we issued an additional $200 million in principal amount of our 10% Senior Notes due 2017 (collectively, the "2017 Notes").

On February 17, 2016, we closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of our outstanding 2017 Notes. In satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the then outstanding aggregate principal amount of 2017 Notes, we (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of our new 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately 1.1 million shares of Predecessor common stock. Following the completion of the February Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.

On September 27, 2016, we closed private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of our outstanding 2017 Notes and 2021 Notes. In satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the then outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the then outstanding aggregate principal amount of 2021 Notes, we issued (i) $243.5 million in aggregate principal amount of our new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately 3.5 million shares of Predecessor common stock. We also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including, September 27, 2016. Following the consummation of the September Exchange, there were $22.7 million in aggregate principal amount of the 2017 Notes outstanding and $14.2 million in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes.

On March 31, 2017, we redeemed the remaining outstanding 2017 Notes at a redemption price of $22.8 million. The redemption was funded by cash on hand and $20 million borrowed under the Old Loan Agreement described below. On December 28, 2017, we issued 2.2 million shares of Predecessor common stock to extinguish $4.8 million of outstanding principal amount of 2021 Notes.

The 2021 PIK Notes accrued interest at a rate of 10% per annum on the principal amount and interest was payable semi-annually in arrears on February 15 and August 15 of each year. We were permitted, at our option, for the first three interest payment dates of the 2021 PIK Notes ending with the February 2018 interest payment, to instead pay interest at (i) the annual rate of 1% in cash plus (ii) the annual rate of 9% PIK (the "PIK Interest") payable by increasing the principal amount outstanding of the 2021 PIK Notes or by issuing additional 2021 PIK Notes in certificated form. We exercised this PIK option in connection with the interest payments due on February 15, 2017, August 15, 2017 and February 15, 2018.

The 2021 Notes accrued interest at a rate of 10% per annum on the principal amount and interest was payable semi-annually in arrears on February 15 and August 15 of each year.

The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to Accounting Standards Codification ("ASC") Topic 470-60 "Troubled Debt Restructurings by Debtors." We determined that the future undiscounted cash flows from the 2021 PIK Notes issued in the September Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes and the 2021 Notes tendered in the September Exchange. Accordingly, no gain or loss on extinguishment of debt was recognized in connection with the September Exchange. The net shortfall of the remaining carrying value of the 2017 Notes and 2021 Notes tendered as compared to the principal amount of the 2021 PIK Notes issued in the September Exchange of $0.6 million was reflected as part of the carrying value of the 2021 PIK Notes. Such shortfall was being amortized under the effective interest method as an addition to interest expense over the term of the 2021 PIK Notes.

We previously determined that the future undiscounted cash flows from the 2021 Notes issued in the February Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the February Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the February Exchange. The excess of the remaining carrying value of the 2017 Notes tendered over the principal amount of the 2021 Notes issued in the February Exchange of $13.9 million was reflected as part of the carrying value of the 2021 Notes. The amount of the excess carrying value attributable to the 2021 Notes tendered in the September Exchange was then reflected as part of the carrying value of the 2021 PIK Notes. The excess carrying value attributable to the remaining 2021 Notes was being amortized under the effective interest method over the term of the 2021 Notes.

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On October 17, 2016, we entered into a multidraw term loan agreement (the "Old Loan Agreement") with Franklin Custodian Funds - Franklin Income Fund ("Franklin"), as a lender, and Wells Fargo Bank, National Association, as administrative agent (the "Agent"), replacing the prior credit agreement with JPMorgan Chase Bank, N.A. Effective August 14, 2018, we entered into a Forbearance Agreement (the "Forbearance Agreement") with the Agent for the lenders with respect to the Old Loan Agreement. Pursuant to the Forbearance Agreement, the Agent and the lenders under the Old Loan Agreement agreed to forbear from taking any action with respect to certain specified events of default occurring under the Old Loan Agreement as a result of our non-payment of interest with respect to the 2021 PIK Notes and 2021 Notes when due and payable on August 15, 2018 under the indentures governing those notes. On August 31, 2018, we entered into a new Multidraw Term Loan Agreement (the "Multidraw Term Loan Agreement"), which replaced the Old Loan Agreement, with the lenders party thereto from time to time (the "Lenders") and the Agent. The Multidraw Term Loan Agreement provided a multi-advance term loan facility in the principal amount of up to $50.0 million. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) were permitted to be used to repay existing debt, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes. On August 31, 2018, we borrowed $50.0 million under the Term Loans, and repaid $32.5 million of outstanding borrowings under the Old Loan Agreement, plus accrued interest and fees and retained the balance of the borrowings for general corporate purposes. As a result, as of December 31, 2018, we had no borrowing availability under the Multidraw Term Loan Agreement.

Effective September 14, 2018, we entered into a Forbearance Agreement (the "Loan Forbearance Agreement") with the Agent for the lenders with respect to the Multidraw Term Loan Agreement. Pursuant to the Forbearance Agreement, the Agent and Lenders agreed to forbear from taking any action with respect to certain anticipated events of default occurring under the Multidraw Term Loan Agreement as a result of the non-payment of interest with respect to th 2021 Notes and 2021 PIK Notes when due and payable on August 15, 2018 and such non-payment continuing for a period of 30 days under the indentures governing the notes. The Loan Forbearance Agreement was effective from September 14, 2018 until the earlier of (i) 11:59 p.m. Eastern time on September 28, 2018 or (ii) the occurrence of any specified forbearance default, which includes, among other things, any event of default under the Multidraw Term Loan Agreement, other than the anticipated events of default or a breach by us of the Loan Forbearance Agreement. On September 28, 2018, October 5, 2018, October 19, 2018 and October 31, 2018, we, the Agent and the Lenders entered in first, second, third and fourth amendments to the Loan Forbearance Agreement that extended the September 28, 2018 deadline to 11:59 p.m. Eastern time on each of October 5, 2018, October 19, 2018, October 31, 2018 and November 6, 2018, respectively. The Loan Forbearance Agreement terminated on the commencement of the Chapter 11 Cases.

Effective September 14, 2018, we entered into (i) a Forbearance Agreement (the "2021 Notes Forbearance Agreement") with certain holders (the "2021 Notes Supporting Holders") of approximately $7.3 million in aggregate principal amount (representing approximately 77.9% of the outstanding principal amount) of the 2021 Notes, and (ii) a Forbearance Agreement (the "2021 PIK Notes Forbearance Agreement" and together with the 2021 Notes Forbearance Agreement, the "Notes Forbearance Agreements") with certain holders (the "2021 PIK Notes Supporting Holders" and together with the 2021 Notes Supporting Holders, the "Supporting Holders") of approximately $194.6 million in aggregate principal amount (representing approximately 70.7% of the outstanding principal amount) of the 2021 PIK Notes.

Pursuant to the Notes Forbearance Agreements, the Supporting Holders agreed to forbear from exercising their rights and remedies under their respective indentures governing the 2021 Notes and the 2021 PIK Notes or the related security documents with respect to certain anticipated events of default occurring under the indentures as a result of the non-payment by us of interest with respect to the 2021 Notes and the 2021 PIK Notes when due and payable on August 15, 2018 and such non-payment continuing for a period of 30 days, until the earlier of (i) 11:59 p.m. Eastern time on September 28, 2018 and (ii) the date the Notes Forbearance Agreements otherwise terminate in accordance with the terms therein (the "Forbearance Period"). Pursuant to the Notes Forbearance Agreements, the Supporting Holders agreed to not deliver any notice or instruction in respect of the exercise of any of the rights and remedies otherwise available under the indentures or the related security documents with respect to such anticipated events of default. The Supporting Holders also agreed to not transfer any ownership in the 2021 Notes and the 2021 PIK Notes held by any of the Supporting Holders during the Forbearance Period other than to potential transferees currently parties to, or who agree in writing to be bound by, the Notes Forbearance Agreements. On September 28,2018, October 5, 2018, October 19, 2018 and October 31, 2018, we and the Supporting Holders entered into first, second, third and fourth amendments to the Notes Forbearance Agreements that extended the September 28, 2018 deadline to 11:59 p.m. Eastern time on each of October 5, 2018, October 19, 2018, October 31, 2018 and November 6, 2018, respectively. The Notes Forbearance Agreements terminated on the commencement of the Chapter 11 Cases described in Note 10.

The face value of the 2021 Notes and the 2021 PIK Notes, including accrued PIK Interest, is classified as liabilities subject to compromise as of December 31, 2018. The Term Loans are reflected net of $0.3 million and $2.0 million of related unamortized deferred financing costs as of December 31, 2018 and 2017, respectively. The adjustments to write off the remaining unamortized deferred financing costs and carrying value adjustments related to the February Exchange and September Exchange are included in reorganization items in the consolidated statement of operations.

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The commencement of the Chapter 11 Cases described in "Overview - Voluntary Reorganization under Chapter 11 of the Bankruptcy Code" above, constituted an event of default that accelerated the obligations under the Multidraw Term Loan Agreement and the indentures governing the 2021 Notes and 2021 PIK Notes. The Multidraw Term Loan Agreement and the indentures governing the 2021 Notes and 2021 PIK Notes provided that as a result of the Petition, the principal and interest due thereunder should be immediately due and payable. However, any efforts to enforce such payment obligations under such debt instruments were automatically stayed as a result of the Chapter 11 Cases, and the creditors' rights of enforcement in respect of such debt instruments were subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Post-Emergence Indebtedness

As discussed in "Overview - Voluntary Reorganization under Chapter 11 of the Bankruptcy Code" above, on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, we entered into the Term Loan Agreement (the “Exit Facility”) with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent. The Exit Facility provides for a $50 million term loan facility.

The proceeds of the Exit Facility were used to repay in full the loans and other obligations under the Multidraw Term Loan Agreement. The maturity date of the Exit Facility is November 8, 2023. The interest rate per annum is equal to (i) in the case of LIBOR Loans (as defined in the Exit Facility), 7.50% per annum and (ii) in the case of Base Rate Loans (as defined in the Exit Facility), 6.50% per annum. The Exit Facility is secured by a first priority lien on substantially all of our assets.

We are subject to a restrictive covenant under the Exit Facility, consisting of maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of our oil and gas properties, before any state, federal, foreign or other income taxes, attributable to total proved reserves, using strip prices then in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the aggregate outstanding principal amount of the term loans to be less than 1.50 to 1.00 as measured on the last day of each calendar. If we fail to maintain the ratio, we may either (i) prepay the outstanding term loans such that after giving effect to such prepayment, the financial covenant is met or (ii) be in default under the Exit Facility, in which case the term loans and all other amounts owed pursuant to the Exit Facility would become immediately due and payable.

The Exit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, entering into mergers, consolidations and sales of assets, and transactions with affiliates and other customary covenants. See Item 1A Risk Factors - "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" for a detailed discussion of these debt covenants and their affect on our business.

The Exit Facility contains customary events of default and remedies for credit facilities of this nature. If we do not comply with the financial and other covenants in the Exit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Exit Facility.

As discussed in "Overview - Voluntary Reorganization under Chapter 11 of the Bankruptcy Code" above, on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, we entered into an indenture (the “Indenture”) with Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral agent, and issued $80 million of our 10% Senior Secured PIK Notes due 2024 (the “2024 PIK Notes”) pursuant thereto.

Interest on the 2024 PIK Notes accrues at a rate of 10% per annum payable semi-annually in kind (“PIK Interest”) on February 15 and August 15 of each year, beginning on August 15, 2019. At the election of our Board of Directors, so long as we have provided notice to the holders of the 2024 PIK Notes and the Trustee of such election at least 30 days prior to any applicable interest payment date, interest on the 2024 PIK Notes for any interest period may instead be payable at the annual rate (i) solely in cash (the “Cash Interest”) or (ii) partially as Cash Interest and partially as PIK Interest. The maturity date of the 2024 Notes is February 15, 2024. The 2024 PIK Notes are secured on a second priority lien basis by the equity of our subsidiary PetroQuest Energy, LLC that also secures the Exit Facility. Pursuant to the terms of an intercreditor agreement, the security interest in those assets that secure the 2024 PIK Notes and the related guarantee will be contractually subordinated to liens thereon that secure the Exit Facility and certain other permitted obligations as set forth in the Indenture. Consequently, the 2024 PIK Notes and the related guarantee will be effectively subordinated to the Exit Facility and such other permitted obligations to the extent of the value of such assets.

We may, at our option, on any one or more occasions redeem all or a portion of the 2024 PIK Notes issued under the Indenture at the redemption prices set forth below (expressed in percentages of principal amount on the redemption date), plus accrued and unpaid Cash Interest together with an amount of cash equal to all accrued and unpaid PIK Interest on the 2024 PIK Notes to be redeemed to, but not including, the redemption date (subject to the right of holders of the 2024 PIK Notes of record

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on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the periods set forth below:

PeriodRedemption Price

February 8, 2019 to February 7, 2020        102.000%

February 8, 2020 to February 7, 2021        101.000%

February 8, 2021 and thereafter            100.000%

Upon the occurrence of certain change of control events, any holder of the 2024 PIK Notes will have the right to cause us to repurchase all or any part of such holder’s 2024 PIK Notes at a repurchase price payable in cash equal to 101% of the principal amount of the 2024 PIK Notes to be repurchased (including any PIK Notes (as defined in the Indenture) or any increase in principal amount of the 2024 PIK Notes in connection with PIK Interest, plus accrued interest to the date of repurchase (subject to the right of holders of record on the relevant record date to receive interest due on the related interest payment date).

Use of Capital: Exploration and Development

Our 2019 capital budget is expected to be substantially higher as compared to 2018 as a result of the East Texas and Austin Chalk drilling activity expected during 2019. 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. We are also pursuing a joint venture in our East Texas assets aimed at bringing in liquidity and reducing our share of drilling capital. To the extent additional capital is required or we are unsuccessful in consummating a joint venture, we may evaluate the sale of additional assets or we may reduce our capital expenditures to manage our liquidity position.

Use of Capital: Acquisitions

On December 20, 2017, we entered into an oil focused play in central Louisiana targeting the Austin Chalk formation through the execution of agreements to acquire interests in approximately 24,600 gross acres. We have invested approximately $15.0 million as of December 31, 2018 in acquisition, engineering and geological cots and issued 2 million shares of Predecessor common stock with respect to these interests. We plan to drill our initial horizontal test well during 2019 utilizing data from existing vertical and unfracked horizontal wells that have been drilled in the area.

We expect to finance our future acquisition activities, if consummated, with cash on hand, 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.

Item 7A    Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

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(b) of the Exchange Act. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded the following:

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i. 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, 2018 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, 2018. 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, 2018 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, 2018 based on these criteria.    

March 28, 2019

/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

Item 9B. Other Information

NONE

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PART III

As previously disclosed, on November 6, 2018, we and our direct and indirect wholly-owned subsidiaries (collectively, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 Cases”) seeking relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Court”). On January 31, 2019, the Court entered an order (the “Confirmation Order”) confirming the Debtors’ First Amended Chapter 11 Plan of Reorganization, as Immaterially Modified as of January 28, 2019 (as amended, modified or supplemented from time to time, the “Plan”) under Chapter 11 of the Bankruptcy Code. On February 8, 2019 (the “Effective Date”), the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases. The Plan includes the appointment of a new board of directors as described below. On the Effective Date, the following members of the Company’s then-existing board of directors were deemed to have resigned as directors of the Company: William W. Rucks, IV, E. Wayne Nordberg, Charles F. Mitchell, II, MD, J. Gerard Jolly and W. J. Gordon, III. None of the resignations resulted from any disagreement with the Company regarding any matter related to the Company’s operations, policies, or practices.

Item 10.        Directors, Executive Officers and Corporate Governance

Executive Officers and Directors

The following table provides information regarding our current executive officers and directors. Pursuant to the Plan, the new board of directors of the Company (the “Board”) as of the Effective Date consists of five members: Neal P. Goldman (Chairman), Charles T. Goodson, David I. Rainey, Harry F. Quarls, and J. Bradley Juneau.

NameAgePosition

Charles T. Goodson            63    Chief Executive Officer, President & Director

J. Bond Clement                47    Executive Vice President, Chief Financial Officer & Treasurer

Arthur M. Mixon, III            60    Executive Vice President - Operations and Production

Neal P. Goldman                49    Director and Chairman of the Board

J. Bradley Juneau                59    Director

Harry F. Quarls                66    Director

David I. Rainey                64    Director

Charles T. Goodson

Chief Executive Officer, President & Director

Mr. Goodson has served as our Chief Executive Officer since September 1998 and also served as our Chairman of the Board from May 2000 through the Effective Date.  He has also served as our President since July 2004.   From 1995 to 1998, Mr. Goodson was President of American Explorer, L.L.C., a private oil and gas exploration and production company we subsequently acquired.  Since 1985, he has served as President and 50% owner of American Explorer, Inc., an oil and gas operating company which formerly operated properties for us.  From 1980 to 1985, he worked for Callon Petroleum Company, first as a landman, then District Land Manager and then Regional Land Manager.  He began his career in 1978 as a landman for Mobil Oil Corporation.  In addition, Mr. Goodson is a member of the Lafayette Association of Petroleum Landmen and the American Association of Petroleum Landmen. He is also a member of IberiaBank's Lafayette Advisory Board, the Federal Reserve Bank of Atlanta Energy Advisory Council and a past member of the Board of Directors of Our Lady of Lourdes Regional Medical Center, the Governor’s Energy Policy Advisory Commission and the Young President’s Organization (YPO). His civic organization memberships include the Lafayette Chamber of Commerce and the United Way of Acadiana. Mr. Goodson is past Regional Governor - Louisiana (Southwest) for the Independent Petroleum Association of America (IPAA) and past Chairman of the Louisiana Independent Oil and Gas Association (LIOGA). As a result of these and other professional experiences, and his longevity with the company, Mr. Goodson possesses broad and particular knowledge of all aspects of the oil and gas production industry as well as extensive leadership experience as our Chief Executive Officer and President and former Chairman.

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J. Bond Clement

Executive Vice President, Chief Financial Officer and Treasurer

Mr. Clement has served as our Executive Vice President, Chief Financial Officer and Treasurer since October 2009.  He also served as our Senior Vice President and Chief Accounting Officer from March 2008 to October 2009, as our Controller from October 2004 until March 2008, as a Vice President from May 2006 to August 2007 and as our Vice President of Finance from August 2007 to March 2008. Prior to joining us in October 2004, Mr. Clement served in a variety of investor relations, corporate finance and accounting related management positions at Stone Energy Corporation from 1997 to 2004 and worked for Freeport-McMoRan Inc. from 1996 to 1997.  From 1993 to 1996, Mr. Clement worked at Arthur Andersen LLP primarily auditing clients focused in the energy industry. Mr. Clement earned a Bachelor of Science Degree in Accounting, Cum Laude, from Louisiana State University in 1993 and was a Certified Public Accountant.

Arthur M. Mixon, III

Executive Vice President - Operations and Production

Mr. Mixon has served as our Executive Vice President - Operations and Production since October 2009.  He also served as our Executive Vice President - Exploration and Production from May 2006 to October 2009 and as our Senior Vice President-Operations from January 2001 to May 2006.  From 1981 to 2001, Mr. Mixon accumulated 20 years of experience with BP Amoco PLC, a public petroleum and petrochemical company, in a variety of engineering, supervisory and management positions in the United States, Trinidad and Tobago, and Venezuela.  He is a member of numerous industry organizations including the Society of Petroleum Engineers, American Association of Drilling Engineers, American Petroleum Institute, Louisiana Oil and Gas Association, National Ocean Industries Association, as well as the Oilfield Christian Fellowship.  Mr. Mixon is a Registered Professional Engineer, receiving a Bachelor of Science Degree in Petroleum Engineering from Louisiana State University in 1980. 

Neal P. Goldman

Chairman of the Board

Mr. Goldman has served as a director of the Company and as our Chairman of the Board since the Effective Date. He has over 25 years of experience in investing and working with companies to maximize shareholder value. He is currently the Managing Member of SAGE Capital Investments, LLC, a consulting firm specializing in independent board of director services, restructuring, strategic planning and transformations for companies in multiple industries including energy, technology, media, retail, gaming and industrials. He also currently serves as Chairman of the Board of Talos Energy Inc. and is a member of the boards of Ultra Petroleum, Midstates Petroleum, and Ditech Holdings. As a board member, Mr. Goldman has demonstrated expertise representing public and private companies experiencing complex corporate governance and/or financial situations. Mr. Goldman received a BA from the University of Michigan and a MBA from the University of Illinois.

J. Bradley Juneau

Director

Mr. Juneau has served as a director of the Company since the Effective Date. Mr. Juneau is the sole manager of the general partner of Juneau Exploration, L.P. (“JEX”), a company involved in the exploration and production of oil and natural gas. Prior to forming JEX in 1998, Mr. Juneau served as senior vice president of exploration for Zilkha Energy Company from 1987 to 1998. Prior to joining Zilkha Energy Company, Mr. Juneau served as staff petroleum engineer with Texas International Company for three years, where his principal responsibilities included reservoir engineering, as well as acquisitions and evaluations. Prior to that, he was a production engineer with Enserch Corporation in Oklahoma City. He is co-founder of the Contango ORE, Inc. (“CORE”) and was appointed President, Chief Executive Officer and a director of CORE in August 2012 after the Company’s co-founder, Mr. Kenneth R. Peak, received a medical leave of absence. In April 2013, Mr. Juneau was elected Chairman. Mr. Juneau previously served as a director of Contango Oil & Gas Company from April 2012 to March 2014.  Mr. Juneau is currently a director of Talos Energy, Inc. and Castex Energy.  Mr. Juneau holds a Bachelor of Science degree in Petroleum Engineering from Louisiana State University. Mr. Juneau brings energy investing experience, as well has industry knowledge, as well as experience leading numerous energy companies.

Harry F. Quarls

Director

Mr. Quarls has served as a director of the Company since the Effective Date and of Rosehill Resources since April 2017. He also serves as Chairman of the Board of SH 130 Concessions Company LLC. Mr. Quarls previously served as Chairman of the Board of Directors of Penn Virginia Corporation, Woodbine Acquisition Corporation, US Oil Sands Corporation and Trident

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Resources Corp. and as a director for Fairway Resources LLC and Opal Resources LLC. He was previously a Managing Director at Global Infrastructure Partners for over a decade retiring in 2017. He was the Managing Director and Practice Leader for Global Energy at Booz & Co., a leading international management consulting firm, and a member of Booz’s Board of Directors. Mr. Quarls earned an M.B.A. degree from Stanford University and holds ScM. and B.S. degrees, both in chemical engineering from M.I.T. and Tulane University, respectively. Mr. Quarls brings considerable financial and energy investing experience, as well as experience on the boards of numerous public and private energy companies.

David I. Rainey

Director

Dr. Rainey has served as a director of the Company since the Effective Date. From 2017 to 2018, he served on various committees and as an independent director at Stone Energy Corporation and he currently serves as a director at Switch Energy Alliance. Dr. Rainey retired from BHP Billiton in November 2016, having served as President Petroleum Exploration and Chief Geoscientist. Previously, he served in various positions of increasing responsibility for 31 years at BP, with his final roles as Vice President Gulf of Mexico Exploration, and Vice President Science, Technology, Environment and Regulatory Affairs. He was actively involved in various diversity initiatives at BP beginning in the 1990s through 2011. He is an active member of the National Association of Corporate Directors (NACD) and is recognized as a NACD Governance Fellow. He serves on the Houston On Board Advisory Counsel to the Greater Houston Women’s Chamber of Commerce, he is actively involved in the American Cancer Society and he is an inaugural member of the Gulf Coast Chapter for the Society’s “CEO’s Against Cancer” initiative. He is a member of the Advisory Counsel to the Geology Foundation at the Jackson School of Geosciences at the University of Texas at Austin. In 2002, he was recognized as the American Association of Petroleum Geologists’ Michael T Halbouty Lecturer. Dr. Rainey completed executive education programs at MIT Sloan School of Business in 2008, at Stanford University Graduate School of Business in 2002 and at Northwestern University Kellogg School of Management in 1991. He earned both his Ph.D. (1980) and bachelor’s degree with Honors (1976) in Geology from the University of Edinburgh.

Director Independence

Our Board of Directors has affirmatively determined that Neal P. Goldman, J. Bradley Juneau, Harry F. Quarls, and David I. Rainey are independent.

Board Structure, Corporate Governance Guidelines and Nominations Process

Our Board of Directors is governed by PetroQuest’s amended and restated certificate of incorporation, bylaws, charters of the standing committees of the Board and the laws of the State of Delaware. Our amended and restated certificate of incorporation provides that the total number of directors constituting the Board will initially be five directors with an initial term of office to expire at the 2020 annual meeting of the stockholders to take place in 2020 (the “Initial Term”). Under our amended and restated certificate of incorporation, certain of our stockholders have a right to elect the members of the Board as follows:

• On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Class B Holder (as defined in our amended and restated certificate of incorporation) was issued one share of Class B Common Stock. The Class B Holder has the right to elect two directors. The initial term of such directors is the Initial Term, and the Class B Holder will continue to have the right to elect two directors for so long as Corre (as defined in our amended and restated certificate of incorporation) holds at least 20% of the then-outstanding Class A Common Stock (excluding shares of Class A Common Stock issued pursuant to an incentive plan or other incentive arrangement approved by the Board). If Corre holds less than 20% of the then-outstanding Class A Common Stock, the Class B Holder will have the right to elect one director for so long as Corre holds at least 10% of the then-outstanding Class A Common Stock (excluding any shares of Class A Common Stock issued pursuant to an incentive plan or other incentive arrangement approved by the Board). Harry F. Quarls and J. Bradley Juneau are the directors that have been elected by the Class B Holder.

• On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Class C Holder (as defined in our amended and restated certificate of incorporation) was issued one share of Class C Common Stock. The Class C Holder has the right to elect two directors. The initial term of such directors is the Initial Term, and the Class C Holder will continue to have the right to elect two directors for so long as MacKay (as defined in our amended and restated certificate of incorporation) holds at least 20% of the then-outstanding Class A Common Stock (excluding shares of Class A Common Stock issued pursuant to an incentive plan or other incentive arrangement approved by the Board). If MacKay holds less than 20% of the then-outstanding Class A Common Stock, the Class C Holder will have the right to elect one director for so long as MacKay holds at least 10% of the then-outstanding Class A Common Stock (excluding any shares of Class A Common Stock issued pursuant to an incentive plan or other incentive arrangement approved by the Board). Neal P. Goldman and David I. Rainey are the directors that have been elected by the Class C Holder.

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• One director will be elected by the holders of a plurality in voting power of the outstanding shares of Class A Common Stock, who initially is the Chief Executive Officer (such Chief Executive Officer to serve as a member of the Board for the Initial Term).

The Corporate Governance Guidelines form an important framework for our Board’s corporate governance practices and assist the Board in carrying out its responsibilities.  The Board reviews these guidelines and the committee charters periodically to consider the need for amendments or enhancements. Information contained on or available through our website is not a part of or incorporated into this Form 10-K or any other report that we may file with or furnish to the SEC.

As previously disclosed, on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, we adopted amended and restated bylaws for the Company and as a result changes were made to the process by which a stockholder may nominate an individual to stand for election to our Board of Directors at our annual meeting of stockholders. Historically, we have not had a formal policy concerning stockholder nominations of individuals to stand for election to the Board, other than the provisions contained in our bylaws.

Our amended and restated bylaws provide that any stockholder wishing to submit a candidate for consideration should send to the Corporate Secretary, at 400 E. Kaliste Saloom Road, Suite 6000, Lafayette, Louisiana 70508, the information detailed in our amended and restated bylaws, which should be submitted and received, and updated as necessary, subject to the deadlines detailed therein.

Board Committees

Shortly after the appointment of the Board on the Effective Date, threestanding committees of the Board were established comprised of non-employee directors: an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee. These committees are governed by charters adopted by the Board. The charters for the Audit Committee, Compensation Committee and a Nominating and Corporate Governance Committee were adopted by the Board on March 26, 2019. The charters establish the purposes of the committees as well as committee membership guidelines. The charters also define the authority, responsibilities and procedures of the committee in relation to the committee’s role in supporting the Board and assisting the Board in discharging its duties in supervising and governing the Company.

Audit Committee. The current members of the Audit Committee are Neal P. Goldman, J. Bradley Juneau, Harry F. Quarls (Chairman)and David I. Rainey. Our Board of Directors has determined that all of the members of the committee are independent. The committee operates under a written charter adopted by our Board of Directors. The committee assists the Board in overseeing (i) the integrity of PetroQuest’s financial statements, (ii) PetroQuest’s compliance with legal and regulatory requirements, (iii) the independent auditor’s qualifications and independence, and (iv) the performance of PetroQuest’s internal auditors (or other personnel responsible for the internal audit function) and independent auditor. In so doing, it is the responsibility of the committee to maintain free and open communication between the directors, the independent auditor and the financial management of PetroQuest. The committee is directly responsible for the appointment, compensation, retention and oversight of the work of the independent auditor for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for PetroQuest. The independent auditor reports directly to the committee.

Compensation Committee. The current members of the Compensation Committee are Neal P. Goldman, J. Bradley Juneau, Harry F. Quarls, and David I. Rainey (Chairman). Our Board of Directors has determined that all of the members of the committee are independent.

Nominating and Corporate Governance Committee. The current members of the Nominating and Corporate Governance Committee are Neal P. Goldman, J. Brad Juneau (Chairman), Harry F. Quarls and David I. Rainey. Our Board of Directors has determined that all of the members of the committee are independent.

Code of Ethics

Our Predecessor's board of directors adopted a Code of Business Conduct and Ethics that remains applicable to all employees, officers and members of our existing Board. The Code of Business Conduct and Ethics is available on our website at www.petroquest.com. We intend to post amendments to or waivers from the Code of Business Conduct and Ethics (to the extent applicable to our chief executive officer or chief financial officer) at this location on our website. Information contained on or available through our website is not a part of or incorporated into this Form 10-K or any other report that we may file with or furnish to the SEC.

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Items 11        Executive Compensation

Named Executive Officer Compensation

Summary Compensation Table. The following table summarizes the compensation of our principal executive officer, as well as our two other most highly compensated executive officers, for the fiscal years ended December 31, 2018 and 2017. We refer to these individuals in this Form 10-K as the “named executive officers.”

Summary Compensation Table for Fiscal Years Ended December 31, 2018 and 2017
Name and Principal Position	Year	Salary ($) (1)	Bonus ($) (2)	Stock Awards including Stock Units($) (3)	Option Awards ($) (3)	Non-Equity Incentive Plan Compen-sation ($) (4)	All Other Compen-sation ($) (5)	Total ($)
Charles T. Goodson	2018	668,367	221,520	8,858	0	211,971	66,635	1,177,351
Chief Executive Officer	2017	668,367	105,029	593,041	24,486	188,891	81,663	1,661,477
and President
J. Bond Clement	2018	394,748	57,500	2,705	0	125,209	40,308	620,470
Executive Vice President, Chief	2017	394,747	62,032	319,936	14,463	57,508	45,497	894,183
Financial Officer and Treasurer
Arthur M. Mixon, III	2018	394,748	57,500	2,766	0	124,709	51,174	630,897
Executive Vice President –	2017	394,747	62,032	319,936	14,463	57,009	49,884	898,071
Operations and Production

(1) Effective January 1, 2017, the annual base salaries of Messrs. Goodson, Clement and Mixon were increased to $668,367, $394,747, and $394,747, respectively.

(2) In 2017, the Compensation Committee awarded a discretionary cash bonus of 16.5% of 2016 base salary to each of the named executive officers in recognition of their efforts with respect to the ongoing execution of the company’s operations and financial strategies as established by the Board. In recognition of Mr. Goodson's efforts with respect to recent joint ventures, the Committee awarded him an additional discretionary bonus of $91,520 in February of 2018. On November 5, 2018, the Company awarded discretionary bonuses of $130,000, $57,500 and $57,500 to Messrs. Goodson, Clement and Mixon, respectively. See "- Named Executive Officer Compensation Arrangements-2018 Annual Cash Bonus Plan” below.

(3) The amounts in the “Stock Awards” and “Option Awards” columns reflect the aggregate grant date fair value computed in accordance with FASB ASC Topic 718, of awards pursuant to the 2013 Incentive Plan, 2016 Incentive Plan and the Long-Term Cash Incentive Plan. Assumptions used in the calculation of these amounts are included in “Note 6 – Share-Based Compensation”. As discussed above under Items 1 and 2. "Business and Properties-Voluntary Reorganization under Chapter 11 of the Bankruptcy Code”, on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, all of the Predecessor’s common stock and any share-based compensation based on such common stock was cancelled with the former holders thereof not receiving any consideration in respect thereof.

(4) In January 2018, the Compensation Committee approved the scorecard under the Annual Cash Bonus Plan, with a payout of approximately 30% of salary to Messrs. Goodson, Clement and Mixon, respectively.

(5) See table below for reconciliation of All Other Compensation for 2018.

Name	401(k) Matching Contribution		Medical and Dental Insurance		Life Insurance Premiums		Organization Dues		Total
Charles T. Goodson	$	16,500	$	16,366	$	31,509	$	2,260	$	66,635
J. Bond Clement	8,250		23,624		7,334		1,100		40,308
Arthur M. Mixon, III	16,500		16,366		15,951		2,357		51,174

Narrative Disclosure to Summary Compensation Table. See “- Named Executive Officer Compensation Arrangements” below for the material terms of our employment agreements and termination agreements with our named executive officers, as well as our other compensation arrangements with our named executive officers. See the footnotes to the Summary Compensation Table for narrative disclosure with respect to that table.

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Outstanding Equity Awards at Fiscal Year-End Table. The following table shows the number of shares covered by exercisable and unexercisable options, shares of restricted stock units, phantom stock units and performance units that have not vested for which transfer restrictions had not yet lapsed held by our named executive officers on December 31, 2018. As discussed above under Items 1 and 2. "Business and Properties-Voluntary Reorganization under Chapter 11 of the Bankruptcy Code”, on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, all of the Predecessor’s common stock and any share-based compensation based on such common stock as disclosed in the following table was cancelled with the former holders thereof not receiving any consideration in respect thereof.

Outstanding Equity Awards at Fiscal Year-End December 31, 2018
	Option Awards					Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable		Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($) (1)	Equity Incentive Plan Awards; Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)		Equity Incentive Plan Awards; Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (1)
Charles T. Goodson	27,898	-		28.33	10/09/2019	-	-
	15,441	-		30.16	09/09/2021	-	-
	21,458			16.73	11/12/2023	-	-
	28,334	14,166	(2)	4.36	3/15/2026
	21,893	10,946	(3)	3.96	9/26/2026
	99,933	49,966	(3)	3.17	9/26/2026
	6,378	12,752	(4)	1.85	11/12/2027
	-	-		-	-	28,694	115
								93,216	(6)	373
									(7)	0
J. Bond Clement	11,817	-		28.33	10/09/2019	-	-
	7,475	-		30.16	09/09/2021	-	-
	9,244	-		16.73	11/12/2023	-	-
	23,334	11,666	(2)	4.36	3/15/2026
	66,667	33,334	(3)	3.17	9/27/2026
	3,767	7,532	(4)	1.85	11/12/2027
	-	-		-	-	16,947	68
								49,548	(6)	198
									(7)	0
Arthur M. Mixon, III	13,739	-		28.33	10/09/2019	-	-
	8,449	-		30.16	09/09/2021	-	-
	9,505	-		16.73	11/12/2023	-	-
	23,334	11,666	(2)	4.36	3/15/2026
	66,667	33,333	(3)	3.17	9/27/2026
	3,767	7,532	(4)	1.85	11/12/2027
	-		-	-	-	16,947	68
								49,548	(6)	198
									(7)	0

(1) Calculated based upon the closing market price of our common stock on December 29, 2018, which was $.004 per share.

(2) These options would have vested on March 15, 2019.

(3) These options would have vested on September 27, 2019.

(4) These options would have vested in two equal installments on each of November 12, 2019 and 2020.

(5) These restricted stock units would have vested in two equal installments on each of November 12, 2019 and 2020.

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(6) Represents phantom stock units awarded on November 12, 2017 and that would have vested in two installments and be paid in cash on each of November 12, 2019 and 2020.

(7) Represents performance units awarded on November 12, 2017 that would have vested in three installments and be paid in cash on January 1, 2019, January 1, 2020 and January 1, 2021.

Named Executive Officer Compensation Arrangements

Pre-Effective Date Employment Agreements and Potential Benefits Upon Termination or Change-in-Control. Prior to the Effective Date, we had employment agreements with our named executive officers Charles T. Goodson, J. Bond Clement and Arthur M. Mixon, III providing for annual base salaries of $668,367, $394,747 and $394,747, respectively. We also had termination agreements with Messrs. Goodson, Clement and Mixon providing for the payment of severance benefits upon a “change in control” and subsequent termination of the executive’s employment within two years after such “change in control” by us other than for “cause” or by the executive for “good reason.”

Pre-Effective Date Management Incentive Plans. As discussed above under “Items 1 and 2. Business and Properties - Voluntary Reorganization under Chapter 11 of the Bankruptcy Code”, on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, all of the Predecessor’s common stock and any share-based compensation based on such common stock was cancelled with the former holders thereof not receiving any consideration in respect thereof.

2018 Annual Cash Bonus Plan. In November 2018, the Board, in consultation with its independent compensation advisors, adopted the 2018 Annual Cash Bonus Plan and established a total cash pool of $1,500,000 (the "Cash Pool") to reward certain key employees of the Company and its subsidiaries for their performance, based on a review of certain criteria determined by the Compensation Committee of the Board. On each of November 5, 2018 and March 8, 2019, the Company awarded one fourth of the Cash Pool as bonuses to certain employees of the Company, including $130,000, $57,500 and $57,500 to Messrs. Goodson, Clement and Mixon, respectively, on each of those dates. The remaining portion of the Cash Pool will be awarded to employees on a quarterly basis in the second and third quarters of 2019. Messrs. Goodson, Clement and Mixon will receive an additional $260,000, $115,000 and $115,000, respectively.

Post-Effective Date Employment Agreements and Potential Benefits Upon Termination or Change-in-Control. On the Effective Date and pursuant to the Plan and Confirmation Order, we entered into new employment agreements with our named executive officers Charles T. Goodson, J. Bond Clement and Arthur M. Mixon, III providing for annual base salaries of $668,367, $394,747 and $394,747, respectively.

Each of the employment agreements has a term of one year with automatic one-year renewals unless either party provides the other with at least 60 days advance written notice of non-renewal. In the event the agreement is terminated by us without “cause” or due to the death or “disability” of the executive, the executive or his estate will receive, subject to certain conditions, severance equal to his annual base salary, payable in equal semi-monthly installments, for 12 months following the date of termination. In addition, in the event the agreement is terminated by us without “cause”, we will continue, subject to certain conditions, the executive’s health and welfare benefits at our cost for 12 months following the date of termination. Each agreement prohibits the executive from engaging in various activities outside his employment with us without the Company’s approval and prohibits the disclosure of confidential information. In addition, each agreement contains a non-competition agreement and non-solicitation restrictions prohibiting the executive from competing with the Company or soliciting its employees, customers or acquisition prospects during his employment and for one year after termination of the agreement for any reason, subject to certain exceptions.

On the Effective Date and pursuant to the Plan and Confirmation Order, we entered into new termination agreements with Messrs. Goodson, Clement and Mixon. The termination agreements provide for the payment of severance benefits upon certain “change in control” events and subsequent termination of the executive’s employment within two years after such “change in control” by us other than for “cause” or by the executive for “good reason.” Each of the agreements has an initial term through December 31, 2019, with automatic one-year renewals beginning on January 1, 2020 and each January 1 thereafter unless, not later than September 30 of the preceding year, the Company gives notice of the Company’s intent not to extend any of the agreements. Even if the Company timely gives notice, each of the agreements will automatically be extended for 24 months beyond its term if a “change in control” event occurred during the term of any of the agreements. In the event that an executive’s employment is terminated after a “change in control” event by us without “cause” or by the executive for “good reason”, the executive will receive, subject to certain conditions, a lump sum severance payment equal to two times the sum of his annual base salary and most recent annual bonus. In addition, we will continue, subject to certain conditions, the executive’s health and welfare benefits at our cost for 24 months following the date of termination. An executive is not entitled to any benefits under the agreement if the executive’s employment terminates due to the executive’s retirement at age 65, the executive’s “total and permanent disability” or the executive’s death. The Company is required to reimburse the executives for all legal fees and expenses incurred by them as a result of a termination which entitles them to any payments under the agreements, including all such fees and expenses incurred in contesting or disputing any notice of termination under the agreements or in seeking to obtain or enforce any right or benefit provided by the

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agreements or in connection with any tax audit or proceeding relating to the application of excise taxes to any payment or benefit under the agreements.

Post-Effective Date Management Incentive Plan. On the Effective Date and pursuant to the Plan and Confirmation Order, the 2019 Long Term Incentive Plan became effective. The 2019 Long Term Incentive Plan is an equity-based compensation plan providing for and permitting the grant of awards to eligible participants including, among other things, in the form of unrestricted shares of Class A Common Stock, stock options to purchase shares of Class A Common Stock and restricted stock units to be settled in shares of Class A Common Stock, in some cases subject to the satisfaction of certain vesting criteria.

On the Effective Date and pursuant to the Plan and Confirmation Order, restricted stock units (“RSUs”) were awarded to Messrs. Goodson, Clement and Mixon pursuant to the 2019 Long Term Incentive Plan as follows: 379,582 RSUs, 126,528 RSUs and 126,528 RSUs, respectively. The RSUs will be settled in shares of Class A Common Stock within a specified period following vesting. The RSUs are subject to vesting as follows:

• Approximately 41.7% of the RSUs were fully vested upon grant.

• Subject to continuing employment on the vesting date, approximately 16.6% of the RSUs will fully vest on the earlier to occur of (i) the one-year anniversary of the Effective Date or (ii) a “Change in Control” (as defined in the participant’s termination agreement). In the event of the termination of a participant’s employment by the Company for any reason (other than for cause) or in the event of the participant’s death or disability, these RSUs will become fully vested.

• Subject to continuing employment on the vesting date, approximately 41.7% of the RSUs will fully vest on the earlier to occur of (i) the three-year anniversary of Effective Date, (ii) a Change in Control or (iii) the attainment of a 20-trading day volume-weighted average price of $20.00 per share following the date of grant. In the event of the termination of a participant’s employment for any reason (other than death or disability) prior to vesting, these RSUs will be forfeited.

On the Effective Date and pursuant to the Plan and Confirmation Order, stock options (“Options”) were awarded to Messrs. Goodson, Clement and Mixon pursuant to the 2019 Long Term Incentive Plan as follows: 189,791 Options, 63,264 Options and 63,264 Options, respectively. One half of the Options granted to each recipient have an exercise price of $10.00 per share and the other half have an exercise price of $12.50 per share. The Options vest upon the earlier to occur of (i) a 20-trading day volume-weighted average price of a share of the Class A Common Stock at least equal to the applicable exercise price following the date of grant or (ii) a “Change in Control” (as defined in the participant’s termination agreement).

Other Compensation. As executives and employees of the Company, the named executive officers are eligible to participate in the health, dental, short-term disability and long-term disability insurance plans and programs provided to all company employees, but at no cost to the named executive officers. We also provide each named executive officer with term life insurance equal to the executive’s base salary, with minimum and maximum coverage amounts of $400,000 and $500,000, respectively, under a company-sponsored plan at no cost to the named executive. Additionally, named executive officers are offered reimbursement of the cost of $1,000,000 of life insurance upon hire, and an additional $1,000,000 life insurance for every seven (7) years of service to be reimbursed as an expense, guaranteed to age 75. Named executive officers are also eligible to participate in our 401(k) plan, which is generally available to all of our employees. For those who participate, we contribute matching payments of up to 6% of the contributions by the named executive officer to the plan. Named executive officers also receive annual paid vacation time, sick leave, holidays and bereavement days, and are eligible to receive reimbursement of the monthly cost of the local industry-related social and professional club.

Director Compensation

Pre-Effective Date Director Compensation. Our management director was not separately compensated for his service as a director. In May 2018, each of our non-employee directors received half of the annual retainer fee of $37,500 and then received $6,250 monthly for the months of November 2018, December 2018 and January 2019. The Chairman of the Audit Committee received 75% of an additional annual cash retainer of $10,000, the Chairman of the Compensation Committee and the Chairman of the Nominating and Corporate Governance Committee each received 75% of an additional annual cash retainer of $6,667, and the Lead Director received 75% of an additional annual cash retainer of $13,333. Each non-employee director also received an attendance fee of $1,500 per Board or committee meeting attended. The members of our Board of Directors were entitled to reimbursement of their expenses incurred in connection with the attendance at Board and committee meetings in accordance with company policy.

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The following table summarizes the annual compensation for our non-employee directors during 2018.

Director Compensation for Fiscal Year-End December 31, 2018
Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)(1) (2)	Option Awards ($) (3)	Total ($)
W. J. Gordon, III	86,667	3,781	—	90,448
J. Gerard Jolly	127,500	3,781	—	131,281
Charles F. Mitchell, II, M.D.	86,667	3,781	—	90,448
E. Wayne Nordberg	75,500	3,781	—	79,281
William W. Rucks, IV	93,333	3,781	—	97,114

(1)These amounts reflect the aggregate grant date fair value, calculated in accordance with FASB ASC Topic 718, of awards pursuant to our 2016 Long Term Incentive Plan. Assumptions used in the calculation of these amounts are included in “Note 6 – Share-Based Compensation” to Item 8. As discussed above under Items 1 and 2. "Business and Properties-Voluntary Reorganization under Chapter 11 of the Bankruptcy Code”, on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, all of the Predecessor’s common stock and any share-based compensation based on such common stock was canceled with the former holders thereof not receiving any consideration in respect thereof.

(2)As of December 31, 2018, each of Messrs. Gordon, Nordberg, Rucks and Jolly, and Dr. Mitchell had no outstanding shares of restricted common stock or phantom stock units outstanding.

(3)As of December 31, 2018, each of Messrs. Gordon, Nordberg, Rucks and Dr. Mitchell had a total of 27,875 stock options outstanding, and Mr. Jolly had a total of 21,000 stock options outstanding.

Post-Effective Date Director Compensation. On the Effective Date and pursuant to the Plan and Confirmation Order, we adopted a new compensation plan for our non-employee directors as follows:

• an annual cash retainer of $85,000 to any non-employee Chairman of the Board, payable quarterly in advance and pro-rated for any periods of partial service; and

• an annual cash retainer of $70,000 to each non-employee director (other than the Chairman of the Board), payable quarterly in advance and pro-rated for any periods of partial service.

In addition, on the Effective Date and pursuant to the Plan and Confirmation Order, restricted stock units (“RSUs”) were awarded to Messrs. Goldman, Rainey, Quarls, and Juneau pursuant to the 2019 Long Term Incentive Plan as follows: 60,000 RSUs, 45,000 RSUs, 45,000 RSUs and 45,000 RSUs, respectively. The RSUs will vest in 1/3 increments on the first, second and third anniversary of the award date.

We will continue to reimburse all of our directors for their expenses incurred in connection with attendance at Board and committee meetings in accordance with company policy.

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

Principal Stockholders

The following table presents certain information as of March 10, 2019, as to:

• each stockholder known by us to be the beneficial owner of more than five percent of our outstanding shares of Class A common stock,

• each current director,

• each executive officer named in the Summary Compensation Table, and

• all directors and executive officers as a group.

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	Shares Beneficially Owned (1)
Name and Address of Beneficial Owner (2)	Number	Percent of Class
MacKay Shields LLC(3)	4,033,549	43.8	%
Corre Partners Management, LLC(4)	2,609,842	28.4	%
Hotchkis & Wiley Capital Management, LLC (5)	929,031	10.1	%
Charles T. Goodson(6)	158,159	1.7	%
J. Bond Clement(6)	52,720	*
Arthur M. Mixon, III(6)	52,720	*
Neal P. Goldman	0
J. Bradley Juneau	0
Harry F. Quarls	0
David I. Rainey	0
All directors and executive officers as a group (7 persons)	263,599	2.9	%

* Less than 1%

(1) Except as otherwise indicated, all shares are beneficially owned, and the sole investment and voting power is held, by the person named. This table is based on information supplied by officers, directors and principal stockholders and reporting forms, if any, filed with the SEC on behalf of such persons. Based on 9,200,000 shares outstanding on March 10, 2019.

(2) Unless otherwise indicated, the address of all beneficial owners of more than five percent of our shares of Class A common stock set forth above is 400 E. Kaliste Saloom Road, Suite 6000, Lafayette, Louisiana 70508.

(3) The address for MacKay Shields LLC (“MacKay”) is 1345 Avenue of Americas, New York, New York 10105. MacKay has sole power to vote or to direct the vote of and sole power to dispose or to direct the disposition of all of the shares.

(4) The address for Corre Partners Management, LLC (“Corre”) is 12 East 49th Street, 40th Floor, New York, New York 10017. Corre has sole power to vote or to direct the vote of and sole power to dispose or to direct the disposition of all of the shares.

(5) The address for Hotchkis & Wiley Capital Management, LLC (“H&W”) is 725 South Figueroa Street, 39th Floor, Los Angeles, California 90017. H&W has sole power to vote or to direct the vote of 915,570 of the shares and sole power to dispose or to direct the disposition of all of the shares.

(6) Number of shares beneficially owned represents fully vested RSUs that will be settled in shares of Class A common stock on the earlier of (i) termination of employment for any reason, (ii) change in control of the Company or (iii) March 25, 2019.

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information regarding the Predecessor's equity compensation plans as of December 31, 2018. All of the Predecessor's equity compensation plans were canceled upon our emergence from bankruptcy on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (2)
	(a)	(b)	(c)
Equity compensation plans approved by security holders	1,486,823	$6.34	2,000,000
Equity compensation plans not approved by security holders	—	—	—
Total	1,486,823	$6.34	2,000,000

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(1) Includes options outstanding under the 1998 Incentive Plan, as amended and restated effective May 14, 2008 (the “1998 Incentive Plan”), the 2013 Incentive Plan and the 2016 Long Term Incentive Plan. The 1998 Incentive Plan and the 2013 Incentive Plan were frozen in May 2013 and May 2016, respectively.

(2) Includes 2,000,000 shares of common stock available for issuance under the Amended and Restated 2016 Long Term Incentive Plan as approved by shareholders in May 2018.

The following table sets forth information regarding the Successor's equity compensation plans as of February 28, 2019.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (2)	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (3)
	(a)	(b)	(c)
Equity compensation plans approved by security holders (1)	1,143,957	$11.25	200,044
Equity compensation plans not approved by security holders	—	—	—
Total	1,143,957	$11.25	200,044

(1) Represent shares of Successor Class A Common Stock issuable under the under the 2019 Long Term Incentive Plan.

(2) Includes 316,319 shares of Successor Class A Common Stock that may be issued upon the vesting of stock options and 827,638 shares that may be issued upon vesting of restricted stock units (“RSUs”).

(3) Represents the number of shares of Successor Class A Common Stock remaining available for grant under the 2019 Long Term Incentive Plan as of February 28, 2019.

Items 13    Certain Relationships and Related Transactions, and Director Independence

Transactions with Related Persons

Exit Facility. On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, we entered into the Exit Facility with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent. The Exit Facility provides for a $50.0 million term loan facility. The lenders under the Exit Facility are the former lenders under our Multidraw Term Loan Agreement that are clients, funds and/or accounts advised by MacKay and Corre and certain holders of the Company’s Old Notes (as defined below) that subscribed to be a lender pursuant to the syndication process. In addition, on the Effective Date and pursuant to the Plan and Confirmation Order, the Company issued 300,000 shares of Class A Common Stock to certain holders of the Old Notes that are clients, funds and/or accounts advised by MacKay and Corre for their commitment to backstop the Exit Facility. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” above.

2024 PIK Notes. On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Company entered into the Indenture and issued $80.0 million of the 2024 PIK Notes. Certain holders of the 2024 PIK Notes are clients, funds and/or accounts advised by MacKay and Corre. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” above.

Registration Rights Agreement. On the Effective Date and pursuant to the Plan and the Confirmation Order, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with certain recipients of shares of the Class A Common Stock and the 2024 PIK Notes distributed on the Effective Date that are clients, funds, and/or accounts advised by MacKay and Corre (collectively, the “Registration Rights Holders”). See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” above.

The Registration Rights Agreement requires the filing of a shelf registration statement (the “Initial Shelf Registration Statement”) that includes the Registrable Securities (as defined in the Registration Rights Agreement), whose inclusion has been timely requested and subject to certain limitations, with the SEC no later than five business days after the Company files its first Quarterly Report on Form 10-Q with the SEC after the Effective Date, and that the Company use its reasonable best efforts to have the Initial Shelf Registration Statement declared effective as soon as reasonably practicable after the Company files the Initial Shelf Registration Statement (but in no event later than 75 days after it shall have filed such Shelf Registration Statement, unless it is not practicable to do so due to circumstances directly relating to outstanding comments of the SEC relating to the Initial Shelf Registration Statement; provided that the Company is using its reasonable best efforts to address any such comments as promptly

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as possible). The Registration Rights Agreement also provides the Registration Rights Holders the ability to demand registrations or underwritten shelf takedowns subject to certain requirements and exceptions.

In addition, if the Company proposes to register shares of the Class A Common Stock in certain circumstances, the Registration Rights Holders will have certain “piggyback” registration rights, subject to restrictions set forth in the Registration Rights Agreement, to include their shares of the Class A Common Stock in the registration statement.

These registration rights are subject to certain conditions and limitations, including the right of underwriters to limit the Registrable Securities to be included in an underwritten offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. The Company will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective. The registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions, such as blackout periods.

The Registration Rights Agreement also provides that (a) for so long as the Company is subject to the requirements to publicly file information or reports with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, the Company will timely file all information and reports with the SEC and comply with all such requirements, and (b) if the Company is not subject to the requirements of Section 13 or 15(d) of the Exchange Act, make available information necessary to comply with Section 4(a)(7) of the Securities Act, and Rule 144 and Rule 144A, if available, with respect to resales of the Registrable Securities under the Securities Act, at all times, all to the extent required from time to time to enable such Registration Rights Holder to sell Registrable Securities without registration under the Securities Act.

Policies and Procedures with Respect to Related Party Transactions. The charter of the Audit Committee requires that the Audit Committee review, approve and oversee any transaction between the Company and any related person (as defined in Item 404 of Regulation S-K), any insider or affiliated party transaction or course of dealing and any other potential conflict of interest situation on an ongoing basis.

Working Interest and Overriding Royalty Interest Owners. Charles T. Goodson or his affiliates were working interest owners and overriding royalty interest owners in certain properties operated by us or certain properties in which we also held a working interest. As working interest owners, they were required to pay their proportionate share of all costs and were entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners, they were entitled to receive their proportionate share of revenues in the normal course of business.

In our capacity as operator, we incur drilling and operating costs that are billed to our partners based on their respective working interests. At December 31, 2018, our joint interest billing receivable included no amounts due from the related parties discussed above or their affiliates, attributable to their share of costs.

Director Independence

See Item 10. "Directors, Executive Officers and Corporate Governance - Director Independence."

Items 14    Principal Accounting Fees and Services

Ernst & Young, LLP has served as our independent registered public accounting firm since June 28, 2002 and audited our consolidated financial statements included in the Form 10-K.

Audit Fees

The following table sets forth the fees incurred by us in fiscal years 2017 and 2018 for services performed by Ernst & Young LLP:

	2017		2018
Audit Fees(1)		$412,000		$512,000
Audit Related Fees(2)	-		-
Tax Fees(3)	64,900		76,500
All Other Fees(4)	-		-
Total Fees		$476,900		$588,500

(1) Audit fees are fees paid to Ernst & Young LLP for professional services related to the audit and quarterly reviews of our financial statements and for services that are normally provided by the accountant in connection with statutory and regulatory filings. In 2017, audit fees included $25,000 related

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to services provided in connection with other SEC filings and $27,000 related to reimbursement of out-of-pocket expenses. In 2018, audit fees included $31,000 related to reimbursement of out-of-pocket expenses.

(2) Audit related fees are fees paid to Ernst & Young LLP for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements that are not reported above under “Audit Fees.”

(3) Tax fees are fees paid for tax compliance (including filing state and federal tax returns), tax advice and tax planning. Tax fees do not include fees for services rendered in connection with the audit.

(4) No other fees for professional services were paid to Ernst & Young LLP with respect to the fiscal years ended December 31, 2017 and 2018.

Policy on Audit Committee Pre-Approval of Audit and Non-Audit Services of Independent Registered Public Accounting Firm

The Audit Committee’s policy is to pre-approve all audit and non-audit services provided by the independent registered public accounting firm, subject to certain de minimis or other exceptions. These services may include audit services, audit-related services, tax services and other services. Pre-approval is generally provided for up to one year and any pre-approval is detailed as to the particular service or category of services and is generally subject to a specific budget. The committee may delegate the authority to pre-approve the retention of the independent registered public accounting firm for permitted non-audit services to one or more members of the committee, provided that such persons are required to present the pre-approval of any permitted non-audit service to the committee at the next meeting following any such pre-approval. None of the fees paid to the independent registered public accounting firm under the categories Audit-Related, Tax and All Other Fees described above were approved by the Audit Committee after services were rendered pursuant to the de minimis exception established by the SEC.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) 1. FINANCIAL STATEMENTS

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-31 of this Form 10-K:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2018 and 2017

Consolidated Statements of Operations for the three years ended December 31, 2018

Consolidated Statements of Comprehensive Loss for the three years ended December 31, 2018

Consolidated Statements of Cash Flows for the three years ended December 31, 2018

Consolidated Statements of Stockholders’ Equity for the three years ended December 31, 2018

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.

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3. EXHIBITS:

**#2.1	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).
**#2.2	Purchase and Sale Agreement dated as of April 20, 2016, by and between PetroQuest Energy, L.L.C. and GR Woodford Properties, LLC (incorporated herein by reference to Exhibit 2.1 to Form 10-Q filed on August 3, 2016).
2.3	First Amended Chapter 11 Plan of Reorganization, as Immaterially Modified as of January 28, 2019 of PetroQuest Energy, Inc. and its Debtor Affiliates (incorporated herein by reference to Exhibit 2.1 to Form 8-K filed on January 31, 2019).
3.1	Amended and Restated Certificate of Incorporation of PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to Form 8-K filed on February 11, 2019).
3.2	Amended and Restated Bylaws of PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Form 8-K filed on February 11, 2019).

4.1	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).
4.2	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).
4.3	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).
4.4	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).
4.5	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).
4.6	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).
4.7	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).
4.8	First Supplemental Indenture, dated as of September 13, 2016, among 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 September 14, 2016).
4.9	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).
4.10	Waiver of Registration Rights, dated as of September 13, 2016, among PetroQuest Energy, Inc., the Subsidiary Guarantors and Seaport Global Securities LLC (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on September 14, 2016).

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4.11	Indenture, dated September 27, 2016, among 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 September 27, 2016).
4.12	Registration Rights Agreement, dated September 27, 2016, among PetroQuest Energy, Inc., the Subsidiary Guarantors identified therein, Jefferies LLC and Seaport Global Securities LLC (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on September 27, 2016).
4.13	Indenture dated as of February 8, 2019, among PetroQuest Energy, Inc., the guarantors party thereto and Wilmington Trust, N.A. as the trustee and collateral agent and form of 10% Senior Secured PIK Note due 2024 (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed on February 11, 2019).
4.14	Registration Rights Agreement dated as of February 8, 2019, by and among PetroQust Energy, Inc. and the holders party thereto (incorporated herein by reference to Exhibit 4.3 to Form 8-K filed on February 11, 2019).
†10.1	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).
†10.2	PetroQuest Energy, Inc. Annual Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on May 13, 2010).
†10.3	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).
†10.4	PetroQuest Energy, Inc. 2012 Employee Stock Purchase Plan (incorporated herein by reference to Appendix A to Schedule 14A filed March 28, 2012).
†10.5	PetroQuest Energy, Inc. Long-Term Cash Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed November 15, 2012).
†10.6	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).
†10.7	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).
†10.8	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).

†10.9	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 10.21 to Form 10-K filed February 27, 2009).
†10.10	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).
†10.11	PetroQuest Energy, Inc. 2016 Long Term Incentive Plan (incorporated herein by reference to Appendix A to the Company's Definitive Proxy Statement on Schedule 14A filed on April 7, 2016).
10.12	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).

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10.13	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).
10.14	Multidraw Term Loan Agreement, dated as of October 17, 2016, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., Franklin Custodian Funds - Franklin Income Fund, and Wells Fargo Bank, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on October 17, 2016).
#10.15	Lease Acquisition Agreement, effective as of December 18, 2017, between Navitas Oil & Gas, LLC and PetroQuest Energy, L.L.C. (incorporated herein by reference to Exhibit 10.28 to Form 10-K filed on March 8, 2018).
#10.16	Purchase and Sale Agreement executed as of January 31, 2018, between PetroQuest Energy LLC and Northstar Offshore Venture LLC (incorporated herein by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on May 8, 2018)
†10.17	PetroQuest Energy, Inc. Amended and Restated 2016 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on May 18, 2018).
10.18	Forbearance Agreement dated August 14, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and Wells Fargo Bank, N.A. (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on August 15, 2018).
10.19	Multidraw Term Loan Agreement dated August 31, 2018 among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., the Lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on August 31, 2018).
10.20	Forbearance Agreement dated as of September 14, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC, Wells Fargo Bank, N.A. and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on September 17, 2018).
10.21	Forbearance Agreement dated as of September 14, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 Notes Supporting Holders (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed on September 17, 2018).
10.22	Forbearance Agreement dated as of September 14, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 PIK Notes Supporting Holders (incorporated herein by reference to Exhibit 10.3 to Form 8-K filed on September 17, 2018).
10.23	First Amendment to Forbearance Agreement dated as of September 28, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC, Wells Fargo Bank, N.A. and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on September 28, 2018).
10.24	First Amendment to Forbearance Agreement dated as of September 28, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 Notes Supporting Holders (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed on September 28, 2018).
10.25	First Amendment to Forbearance Agreement dated as of September 28, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 PIK Notes Supporting Holders (incorporated herein by reference to Exhibit 10.3 to Form 8-K filed on September 28, 2018).
10.26	Second Amendment to Forbearance Agreement dated as of October 5, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC, Wells Fargo Bank, N.A. and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on October 5, 2018).

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10.27	Second Amendment to Forbearance Agreement dated as of October 5, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 Notes Supporting Holders (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed on October 5, 2018).
10.28	Second Amendment to Forbearance Agreement dated as of October 5, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 PIK Notes Supporting Holders (incorporated herein by reference to Exhibit 10.3 to Form 8-K filed on October 5, 2018).
10.29	Third Amendment to Forbearance Agreement dated as of October 19, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC, Wells Fargo Bank, N.A. and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on October 19, 2018).
10.30	Third Amendment to Forbearance Agreement dated as of October 19, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 Notes Supporting Holders (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed on October 19, 2018).
10.31	Third Amendment to Forbearance Agreement dated as of October 19, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 PIK Notes Supporting Holders (incorporated herein by reference to Exhibit 10.3 to Form 8-K filed on October 19, 2018).
10.32	Fourth Amendment to Forbearance Agreement dated as of October 31, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC, Wells Fargo Bank, N.A. and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on October 31, 2018).
10.33	Fourth Amendment to Forbearance Agreement dated as of October 31, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 Notes Supporting Holders (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed on October 31, 2018).
10.34	Fourth Amendment to Forbearance Agreement dated as of October 31, 2018 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and the 2021 PIK Notes Supporting Holders (incorporated herein by reference to Exhibit 10.3 to Form 8-K filed on October 31, 2018).
10.35	Restructuring Support Agreement dated as of November 6, 2018 (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on November 7, 2018).
†10.36	PetroQuest Energy, Inc. 2018 Annual Cash Bonus Plan (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed on November 7, 2018).
10.37	First Amendment to the Restructuring Support Agreement dated as of December 18, 2018 (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on December 21, 2018).
10.38	Term Loan Agreement dated as of February 8, 2019, by and among PetroQuest Energy, L.L.C., as borrower, PetroQuest Energy, Inc., as parent, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.1 to Form 8-K Filed on February 11, 2019).
10.39	Intercreditor Agreement dated as of February 8, 2019, by and among Wells Fargo Bank, National Association, as intercreditor agent, Wilmington Trust, National Association, as collateral agent, PetroQuest Energy, Inc. and PetroQuest Energy, L.L.C. (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed on February 11, 2019).
†10.40	Form of Executive Employment Agreement dated February 8, 2019 between the Company and each of its executive officers (Charles Goodson, J. Bond Clement and Arthur M. Mixon, III) (incorporated herein by reference to Exhibit 10.3 to Form 8-K filed on February 11, 2019).

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†10.41	Form of Termination Agreement dated February 8, 2019 between the Company and each of its executive officers (Charles Goodson, J. Bond Clement and Arthur M. Mixon, III) (incorporated herein by reference to Exhibit 10.4 to Form 8-K filed on February 11, 2019).
†10.42	Form of Indemnification Agreement dated February 8, 2019 between the Company and each of its executive officers and directors (incorporated herein by reference to Exhibit 10.5 to Form 8-K filed on February 11, 2019).
†10.43	PetroQuest Energy, Inc. 2019 Long Term Incentive Plan dated February 8, 2019 (incorporated herein by reference to Exhibit 10.6 to Form 8-K filed on February 11, 2019).
†10.44	Form of Restricted Stock Units Award Agreement dated February 8, 2019 between the Company and each of its executive officers (Charles Goodson, J. Bond Clement and Arthur M. Mixon, III) (incorporated herein by reference to Exhibit 10.7 to Form 8-K filed on February 11, 2019).
†10.45	Form of Stock Option Award Agreement dated February 8, 2019 between the Company and each of its executive officers (Charles Goodson, J. Bond Clement and Arthur M. Mixon, III) (incorporated herein by reference to Exhibit 10.8 to Form 8-K filed on February 11, 2019).
*21.1	Subsidiaries of the Company.
*23.1	Consent of Ryder Scott Company, L.P.
*31.1	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.
*31.2	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.
*32.1	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.
*32.2	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, 2018, as prepared by Ryder Scott Company, L.P.
99.2	Order Confirming First Amended Chapter 11 Plan of Reorganization, as Immaterially Modified as of January 28, 2019, of PetroQuest Energy, Inc. and Its Debtor Affiliates (incorporated herein by reference to Exhibit 99.1 to Form 8-K filed on January 31, 2019).

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.

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†	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

Item 16. Form 10-K Summary

NONE

#65#

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.

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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.

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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.

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SIGNATURES

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 28, 2019.

PETROQUEST ENERGY, INC.
By:	/s/ Charles T. Goodson
	CHARLES T. GOODSON
	President, Chief Executive Officer and Director

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 28, 2019.

By:	/s/ Charles T. Goodson	President, Chief Executive Officer and Director
	CHARLES T. GOODSON	(Principal Executive Officer)
By:	/s/ J. Bond Clement	Executive Vice President, Chief Financial Officer, Treasurer
	J. BOND CLEMENT	(Principal Financial and Accounting Officer)
By:	/s/ Neal P. Goldman	Director and Chairman of the Board
	NEAL P. GOLDMAN
By:	/s/ David I. Rainey	Director
	DAVID I. RAINEY
By:	/s/ Harry F. Quarls	Director
	HARRY F. QUARLS
By:	/s/ J. Bradley Juneau	Director
	J. BRADLEY JUNEAU

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INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets of PetroQuest Energy, Inc. as of December 31, 2018 and 2017	F-2
Consolidated Statements of Operations of PetroQuest Energy, Inc. for the three years ended December 31, 2018	F-3
Consolidated Statements of Comprehensive Loss of PetroQuest Energy, Inc. for the three years ended December 31, 2018	F-4
Consolidated Statements of Cash Flows of PetroQuest Energy, Inc. for the three years ended December 31, 2018	F-5
Consolidated Statements of Stockholders’ Equity of PetroQuest Energy, Inc. for the three years ended December 31, 2018	F-6
Notes to Consolidated Financial Statements	F-7

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

PetroQuest Energy, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of PetroQuest Energy, Inc. (the Company) as of December 31, 2018 and 2017, and the related consolidated statements of operations, comprehensive loss, cash flows and stockholders’ equity for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company's auditor since 2002.

New Orleans, Louisiana

March 28, 2019

F-1

PETROQUEST ENERGY, INC. (Debtor-in-Possession)

Consolidated Balance Sheets (Amounts in Thousands)

	December 31, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	34,891		$	15,655
Revenue receivable	6,364			15,340
Joint interest billing receivable	4,716			6,597
Other receivable	—			7,750
Derivative asset	—			1,174
Deposit for surety bonds	3,550			8,300
Other current assets	3,261			2,125
Total current assets	52,782			56,941
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method	1,361,374			1,369,861
Unevaluated oil and gas properties	23,492			21,854
Accumulated depreciation, depletion and amortization	(1,301,592		)	(1,285,660		)
Oil and gas properties, net	83,274			106,055
Other property and equipment	9,282			9,353
Accumulated depreciation of other property and equipment	(9,056		)	(8,843		)
Total property and equipment	83,500			106,565
Other assets	1,005			792
Total assets	$	137,287		$	164,298
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	11,699		$	32,148
Advances from co-owners	2,020			1,730
Oil and gas revenue payable	7,765			19,344
Accrued interest	639			1,724
Asset retirement obligation	183			687
Derivative liability	—			731
Other accrued liabilities	1,259			6,476
Total current liabilities	23,565			62,840
Multi-draw Term Loan	49,738			27,963
10% Senior Secured Notes due 2021	—			9,821
10% Senior Secured PIK Notes due 2021	—			271,577
Asset retirement obligation	2,297			30,623
Preferred stock dividend payable	—			10,278
Other long-term liabilities	—			131
Total liabilities not subject to compromise	75,600			413,233
Liabilities subject to compromise	323,854			—
Total liabilities	399,454			413,233
Stockholders’ equity:
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares	1			1
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 25,587 and 25,521 shares, respectively	26			26
Paid-in capital	314,268			313,244
Accumulated other comprehensive income	—			278
Accumulated deficit	(576,462		)	(562,484		)
Total stockholders’ equity	(262,167		)	(248,935		)
Total liabilities and stockholders’ equity	$	137,287		$	164,298

See accompanying Notes to Consolidated Financial Statements.

F-2

PETROQUEST ENERGY, INC. (Debtor-in-Possession)

Consolidated Statements of Operations

(Amounts in Thousands, Except Per Share Data)

	Year Ended
	December 31,
	2018			2017			2016
Revenues:
Oil and gas sales	$	87,099		$	108,287		$	66,667
Expenses:
Lease operating expenses	20,552			33,162			28,508
Production taxes	3,198			3,302			354
Depreciation, depletion and amortization	22,667			32,053			28,720
Ceiling test write-down	—			—			40,304
General and administrative	17,564			15,860			26,040
Accretion of asset retirement obligation	322			2,252			2,515
Interest expense	28,147			28,836			30,019
	92,450			115,465			156,460
Other income (expense):
Other income (expense)	248			(408		)	(560		)
	248			(408		)	(560		)
Loss from operations	(5,103		)	(7,586		)	(90,353		)
Reorganization items	4,293			—			—
Income tax expense (benefit)	152			(949		)	543
Net loss	(9,548		)	(6,637		)	(90,896		)
Preferred stock dividend	4,371			5,139			5,349
Net loss available to common stockholders	$	(13,919	)	$	(11,776	)	$	(96,245	)
Loss per common share:
Basic
Net loss per share	$	(0.54	)	$	(0.55	)	$	(5.24	)
Diluted
Net loss per share	$	(0.54	)	$	(0.55	)	$	(5.24	)
Weighted average number of common shares:
Basic	25,581			21,330			18,354
Diluted	25,581			21,330			18,354

See accompanying Notes to Consolidated Financial Statements.

F-3

PETROQUEST ENERGY, INC. (Debtor-in-Possession)

Consolidated Statements of Comprehensive Loss

(Amounts in Thousands)

	Year Ended
	December 31,
	2018			2017			2016
Net loss	$	(9,548	)	$	(6,637	)	$	(90,896	)
Change in fair value of derivatives, net of income tax (expense) benefit of $106, ($165) and $561, respectively	(278		)	5,028			(5,697		)
Comprehensive loss	$	(9,826	)	$	(1,609	)	$	(96,593	)

See accompanying Notes to Consolidated Financial Statements.

F-4

PETROQUEST ENERGY, INC. (Debtor-in-Possession)

Consolidated Statements of Cash Flows

(Amounts in Thousands)

	Year Ended
	December 31,
	2018			2017			2016
Cash flows provided by (used in) operating activities:
Net loss	$	(9,548	)	$	(6,637	)	$	(90,896	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred tax (benefit) expense	152			(949		)	543
Depreciation, depletion and amortization	22,667			32,053			28,720
Ceiling test writedown	—			—			40,304
Accretion of asset retirement obligation	322			2,252			2,515
Share based compensation expense	966			1,447			1,444
Amortization costs and other	1,138			554			2,106
Non-cash PIK interest	2,961			22,895			5,722
Non-cash reorganization items	534			—			—
Payments to settle asset retirement obligations	(863		)	(3,364		)	(3,169		)
Costs incurred to issue 2021 Notes and 2021 PIK Notes	—			—			10,139
Gain on extinguishment of debt	—			(403		)	—
Changes in working capital accounts:
Revenue receivable	8,976			(5,046		)	(3,818		)
Joint interest billing receivable	2,653			610			41,400
Accounts payable and accrued liabilities	(14,458		)	2,970			(72,760		)
Advances from co-owners	290			(600		)	(13,788		)
Net refund (deposit) of surety bonds	4,488			(2,037		)	(6,162		)
Other	(1,429		)	408			1,102
Net cash provided by (used in) operating activities	18,849			44,153			(56,598		)
Cash flows used in investing activities:
Investment in oil and gas properties	(20,559		)	(64,613		)	(30,366		)
Investment in other property and equipment	28			(54		)	(24		)
Sale of oil and gas properties	(6,478		)	10,707			25,482
Sale of unevaluated oil and gas properties	7,750			—			—
Net cash used in investing activities	(19,259		)	(53,960		)	(4,908		)
Cash flows provided by (used in) financing activities:
Net payments for share based compensation	43			(26		)	11
Deferred financing costs	(386		)	(174		)	(3,156		)
Payment of preferred stock dividend	—			—			(1,285		)
Proceeds from borrowings	52,500			20,000			10,000
Repayment of borrowings	(32,500		)	—			—
Redemption of 2017 Notes	—			(22,650		)	(53,626		)
Costs incurred to issue 2021 Notes and 2021 PIK Notes	—			—			(10,139		)
Costs incurred to redeem 2021 Notes	(11		)	—			—
Net cash provided by (used in) financing activities	19,646			(2,850		)	(58,195		)
Net increase (decrease) in cash and cash equivalents	19,236			(12,657		)	(119,701		)
Cash and cash equivalents, beginning of period	15,655			28,312			148,013
Cash and cash equivalents, end of period	$	34,891		$	15,655		$	28,312
Supplemental disclosure of cash flow information:
Cash paid (received) during the period for:
Interest	$	5,341		$	7,432		$	33,206
Income taxes	$	38		$	(94	)	$	(18	)
Reorganization items	$	980		$	—		$	—

See accompanying Notes to Consolidated Financial Statements.

F-5

PETROQUEST ENERGY INC. (Debtor-in-Possession)

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, 2015	$	16	$	1	$	290,432		$	947		$	(454,463	)	$	(163,067	)
Issuance of shares in debt exchange	5		—		12,520			—			—			12,525
Retirement of shares upon vesting of restricted stock	—		—		(200		)	—			—			(200		)
Share-based compensation expense	—		—		1,444			—			—			1,444
Issuance of shares under employee stock purchase plan	—		—		145			—			—			145
Derivative fair value adjustment, net of tax	—		—		—			(5,697		)	—			(5,697		)
Preferred stock dividend	—		—		—			—			(5,349		)	(5,349		)
Net loss	$	—	$	—	$	—		$	—		$	(90,896	)	$	(90,896	)
December 31, 2016	$	21	$	1	$	304,341		$	(4,750	)	$	(550,708	)	$	(251,095	)
Issuance of shares	5		—		7,441			—			—			7,446
Retirement of shares upon vesting of restricted stock	—		—		(10		)	—			—			(10		)
Share-based compensation expense	—		—		1,447			—			—			1,447
Issuance of shares under employee stock purchase plan	—		—		25			—			—			25
Derivative fair value adjustment, net of tax	—		—		—			5,028			—			5,028
Preferred stock dividend	—		—		—			—			(5,139		)	(5,139		)
Net loss	—		—		—			—			(6,637		)	(6,637		)
December 31, 2017	$	26	$	1	$	313,244		$	278		$	(562,484	)	$	(248,935	)
Issuance of shares	—		—		(11		)	—			—			(11		)
Share-based compensation expense	—		—		992			—			—			992
Issuance of shares under employee stock purchase plan	—		—		43			—			—			43
Derivative fair value adjustment, net of tax	—		—		—			(278		)	(59		)	(337		)
Preferred stock dividend	—		—		—			—			(4,371		)	(4,371		)
Net loss	—		—		—			—			(9,548		)	(9,548		)
December 31, 2018	$	26	$	1	$	314,268		$	—		$	(576,462	)	$	(262,167	)

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 an exploration office in The Woodlands, Texas. It is engaged in the exploration, development, acquisition and operation of oil and gas properties in Texas and Louisiana. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to February 8, 2019, and to the pre-emergence company as “Predecessor” for periods prior to February 8, 2019. As discussed in “Note 2-Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” the Company and its wholly owned direct and indirect subsidiaries filed voluntary petitions for bankruptcy relief and subsequently operated as debtors in possession, in accordance with the applicable provisions of the Bankruptcy Code, until emergence on February 8, 2019.

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.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States ("US GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserves and future net cash flows from estimated proved reserves are based on geological and engineering data and depend upon a number of variable factors and assumptions. Changes in estimated proved oil and gas reserves used in the calculation of depreciation, depletion and amortization of oil and gas properties or the present value of the estimated future net cash flows from estimated proved reserves used in the ceiling test could have a material impact on future results of operations.

Bankruptcy Accounting and Financial Reporting

The consolidated financial statements have been prepared in accordance with Accounting Standards Codification ("ASC") 852, Reorganizations, for the period subsequent to the bankruptcy filing. ASC 852 requires that the consolidated financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the Chapter 11 Cases (as defined below) are recorded as reorganization items on the consolidated statement of operations. In addition, the pre-petition obligations that may be impacted by the bankruptcy reorganization process are classified on the consolidated balance sheet in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court (as defined below), even if they may be settled for lesser amounts.

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.

F-7

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 twelve-month, first day of the month, average 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.

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 five years.

Deposit For Surety Bonds

The deposit for surety bonds of $3.6 million and $8.3 million at December 31, 2018 and 2017, respectively, represent cash collateral paid with respect to the Company's surety bonds which secured its offshore decommissioning obligations. The Company received a refund of the majority of the remaining deposits during March 2019.

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 that 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 realizability 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 in accordance with Accounting Standards Update ("ASU") 2014-09 "Revenue from Contracts with Customers". 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.

The Company's sources of revenue are oil, natural gas and natural gas liquids ("NGL") production from its oil and gas properties. Oil and natural gas production is typically sold to purchasers through monthly contracts at negotiated sales prices based on published market indices. The sale takes place at the wellhead for oil production and at the wellhead or gas processing plant for natural gas. NGL production is sold once natural gas is processed and the related liquids are removed at the processing plant. The contracts for sale of NGL production are with the processing plant with prices based on what the processing plant is able to receive from third party purchasers.

Sales of oil, natural gas and NGL production are recognized when the product is delivered and title transfers to the purchaser and payment is generally received one to two months after the sale has occurred. The Company had $6.4 million of revenue receivable at December 31, 2018, comprised of $1.1 million of oil revenue, $4.8 million of natural gas revenue and $0.5 million of NGL revenue.

F-8

The following table includes a disaggregation of revenue by product including the effects of hedges in place (in thousands):

	Year Ended December 31,
	2018		2017		2016
Total oil sales	$	21,027	$	31,258	$	20,614
Total gas sales	50,768		60,922		37,963
Total ngl sales	15,303		16,107		8,090
Total oil and gas sales	$	87,099	$	108,287	$	66,667

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.

	Year Ended December 31,
	2018	2017	2016
Superior Natural Gas	26%	29%	14%
Shell Trading Company	21%	24%	23%
Texla Energy Management	16%	(a)	(a)
Harvest Pipeline Company	12%	(a)	(a)
Laclede Energy Resources	(a)	(a)	17%
BG Group	(a)	(a)	10%

(a) Less than 10 percent

Derivative Instruments

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 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 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, 2018, the Company had no derivative instruments in place. See Note 8 for further discussion of the Company’s derivative instruments.

Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board ("FASB") issued ASU 2016-02, "Leases (Topic 842)," to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This ASU supersedes the lease requirements in Topic 840, Leases, and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within the Company’s consolidated statements of operations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to mineral leases for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves.

F-9

This ASU is effective for fiscal years beginning after December 15, 2018, including the first quarter of 2019. The Company will adopt this standard using the modified retrospective method applied to all leases that exist on January 1, 2019. The Company made certain elections allowing it not to reassess contracts that commenced prior to adoption and to not recognize right-of-use assets or lease liabilities for short-term leases. Upon adoption, the Company expects the right-to-use asset and lease liability reported on its consolidated financial statements to be immaterial.

In August 2017, the FASB issued ASU 2017-12, "Derivative and Hedging," to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its consolidated financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. ASU 2017-12 is effective for public entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with earlier application permitted. The Company is currently evaluating the effect that this new standard may have on its consolidated financial statements.    

Note 2—Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

The Company's overall liquidity position and cash available for capital expenditures have been negatively impacted by weak natural gas prices, declining production and increasing cash interest expense on its outstanding indebtedness. In addition, beginning with the August 15, 2018 interest payment on the Company's 2021 PIK Notes (as defined below), the Company was required to pay interest on its 2021 PIK Notes at 10% in cash (instead of 1% in cash and 9% in payment in kind). The Company elected not to pay the cash interest payments that were due on August 15, 2018 under the Company's 2021 PIK Notes and 2021 Notes (as defined below) which totaled approximately $14.2 million (see Note 10 for additional information).

As a result of the forgoing, the Company engaged in discussions and negotiations with the lenders under the Multidraw Term Loan (as defined below), certain holders of the Company’s 2021 Notes and 2021 PIK Notes, and their legal and financial advisors regarding various alternatives with respect to the Company’s capital structure and financial position, including the significant amount of indebtedness, and the August 15, 2018 interest payments overdue on the Company’s 2021 Notes and 2021 PIK Notes.

As a result of the forgoing discussions and negotiations, on November 6, 2018 (the “Petition Date”), the Company, PetroQuest Energy, L.L.C. (“PQE”) and their direct and indirect wholly owned subsidiaries (collectively, the “Debtors”) filed voluntary petitions (collectively, the “Petition,” and the cases commenced thereby, the “Chapter 11 Cases”) seeking relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).

In connection with the Chapter 11 filing, on the Petition Date, the Debtors entered into a restructuring support agreement (the “Restructuring Support Agreement”) with (i) holders of 81.83% of the Company's 10% Second Lien Senior Secured Notes due 2021 (the “2021 Notes”) issued under that certain Indenture dated as of February 17, 2016, among the Company, the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee and collateral trustee thereunder, (ii) holders of 84.76% of the Company’s 10% Second Lien Senior Secured PIK Notes due 2021 (the “2021 PIK Notes”) issued under that certain Indenture dated as of September 27, 2016, among the Company, the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as indenture trustee and collateral trustee thereunder, and (iii) each of the lenders, or investment advisors or managers for the account of each of the lenders under the multidraw term loan agreement (the "Multidraw Term Loan Agreement"), by and among PQE, the Company, Wells Fargo Bank, National Association, as administrative agent, and lenders holding Term Loans (as defined therein) party thereto from time to time, pursuant to which such parties agreed to support the Plan (as defined below).

On January 31, 2019, the Court entered an order (the “Confirmation Order”) confirming the Debtors’ First Amended Chapter 11 Plan of Reorganization, as Immaterially Modified as of January 28, 2019 (as amended, modified or supplemented from time to time, the “Plan”) under Chapter 11 of the Bankruptcy Code. On February 8, 2019 (the “Effective Date”), the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases. On the Effective Date, TDC Energy, LLC, Pittrans, Inc. and Sea Harvester Energy Development, L.L.C. were dissolved. The remaining Debtors (collectively, the "Reorganized Debtors") continue in existence.

On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Company:

• Adopted an amended and restated certificate of incorporation and bylaws;

• Appointed four new members to the Successor’s board of directors to replace all of the directors of the Predecessor, other than the director also serving as Chief Executive Officer, who was re-appointed pursuant to the Plan;

F-10

• Cancelled all of the Predecessor’s common stock and 6.875% Series B Cumulative Convertible Perpetual Preferred Stock with the former holders thereof not receiving any consideration in respect of such stock;

• Issued to the former holders of the Predecessor’s 2021 Notes and 2021 PIK Notes, (collectively, the “Old Notes”), in exchange for the cancellation and discharge of the Old Notes:

◦ 8,900,000 shares of the Successor’s Class A Common Stock; and

◦ $80 million of the Successor’s 10% Senior Secured PIK Notes due 2024 (the “2024 PIK Notes”);

• Issued 300,000 shares of the Successor’s Class A Common Stock to certain former holders of the Old Notes for their commitment to backstop the Exit Facility (as defined below);

• Issued to the Class B Holder (as defined in the Successor’s amended and restated certificate of incorporation) one share of the Successor’s Class B Common Stock, which confers certain rights to elect directors and certain drag-along rights;

• Issued to the Class C Holder (as defined in the Successor’s amended and restated certificate of incorporation) one share of the Successor’s Class C Common Stock, which confers certain rights to elect directors and certain drag-along rights;

• Entered into a new $50 million senior secured Term Loan Agreement (the “Exit Facility”) upon the repayment and termination of the Predecessor’s Multidraw Term Loan Agreement;

• Entered into a registration rights agreement (the “Registration Rights Agreement”) with certain holders of the Successor’s Class A Common Stock and 2024 PIK Notes; and

• Adopted a new management incentive plan (the “2019 Long Term Incentive Plan”) for officers, directors and employees of the Successor and its subsidiaries, pursuant to which 1,344,000 shares of the Successor’s Class A Common Stock were reserved for issuance.

The foregoing is a summary of the substantive provisions of the Plan and related transactions and is not intended to be a complete description of, or a substitute for a full and complete reading of, the Plan and the other documents referred to above.

Effect of Filing on Creditors

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Petition automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement in the Bankruptcy Court. Although the filing of the Petition triggered defaults on the Debtors’ debt obligations, creditors were stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code.

Rejection of Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and satisfaction of certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtor's estate for damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with any of the Debtors, including where applicable a quantification of the Company’s obligations under any such executory contract or unexpired lease with the applicable Debtor, is qualified by any rights the Company has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto.

Debtor-In-Possession

During the pendency of the Chapter 11 Cases, the Debtors operated as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. In general, as debtors-in-possession under the Bankruptcy Code, the Debtors were authorized to continue to operate as an ongoing business, but were not permitted to engage in transactions outside the ordinary

F-11

course of business without the prior approval of the Bankruptcy Court. Pursuant to motions filed with the Bankruptcy Court that were designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, customers and employees, the Bankruptcy Court authorized the Debtors to conduct their business activities in the ordinary course, including, among other things and subject to the terms and conditions of such orders, authorizing the Debtors to: (i) pay employees' wages and related obligations; (ii) continue to operate their cash management system in a form substantially similar to pre-petition practice; (iii) continue to honor certain obligations related to our royalty obligations; and (iv) pay taxes in the ordinary course.

Reorganization Items

The Debtors have incurred costs associated with the reorganization, primarily legal and professional fees. In accordance with applicable guidance, costs associated with the bankruptcy proceedings have been recorded as reorganization items within the consolidated statement of operations for the year ended December 31, 2018. Reorganization items included $3.8 million related to post petition professional fees and $0.5 million related to adjustments to certain claims relating to the Chapter 11 Cases and to the carrying value of debt classified as liabilities subject to compromise.

Liabilities Subject to Compromise

The consolidated balance sheet as of December 31, 2018 includes amounts classified as liabilities subject to compromise, which represent liabilities which have been allowed as claims in the Chapter 11 Cases. These amounts represent the Debtors' current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process.

Liabilities subject to compromise at December 31, 2018 consisted of the following (in thousands):            

	December 31, 2018
10% Senior PIK Notes due 2021	$	275,046
10% Senior Notes due 2021	9,427
Accrued interest	20,624
Accounts payable to vendors	874
Other long-term liabilities	510
Other accrued liabilities	2,724
Preferred stock dividend payable	14,649
Liabilities subject to compromise	$	323,854

Note 3—Acquisitions and Divestitures

Divestitures:

On April 17, 2017, the Company completed the sale of its interest in the East Lake Verret field in Louisiana for approximately $2.2 million. On December 15, 2017, the Company completed the sale of its saltwater disposal assets in East Texas for approximately $8.5 million. These sales were accounted for as adjustments to the capitalized costs of oil and gas properties.    

On January 31, 2018, the Company sold its Gulf of Mexico properties. The Company received no consideration from the sale of these properties and was required to contribute approximately $3.8 million towards the future abandonment costs for the properties. As a result of the sale, the Company extinguished approximately $28.2 million of its discounted asset retirement obligations. In connection with the sale, the Company received net cash refunds during 2018 totaling $4.5 million related to a depositary account that served to collateralize a portion of the Company's offshore bonds related to these properties. The Company received the majority of the remaining $3.6 million during March 2019, which is included in deposits for surety bonds on the consolidated balance sheet as of December 31, 2018. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

Acquisitions:

On December 20, 2017, the Company entered into an oil focused play in central Louisiana targeting the Austin Chalk formation through the execution of agreements to acquire interests in approximately 24,600 gross acres. The Company has invested approximately $15.0 million in acquisition, engineering and geological costs as of December 31, 2018 and issued 2.0 million shares of Predecessor common stock with respect to these interests.

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Note 4—Equity

As discussed in “Note 2-Voluntary Reorganization under Chapter 11 of the Bankruptcy Code,” on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, all of the Predecessor’s common stock and 6.875% Series B Cumulative Convertible Perpetual Preferred Stock was canceled with the former holders thereof not receiving any consideration in respect thereof. Accordingly, the following discussion relates solely to the Predecessor’s common stock and 6.875% Series B Cumulative Convertible Perpetual Preferred Stock prior to such cancellation.

Common Stock

During December 2017, the Company issued 2.0 million shares of common stock in connection with the acquisition of Austin Chalk acreage (see Note 3). Additionally, during December 2017, the Company issued approximately 2.2 million shares of common stock related to the extinguishment of a portion of the outstanding 2021 Notes (see Note 10).

Convertible Preferred Stock

The Company had 1,495,000 shares of 6.875% Series B Cumulative Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) outstanding as of December 31, 2018 and 2017, all of which were canceled on the Effective Date pursuant to the Plan.    

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

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

In connection with an amendment to the Company's prior bank credit facility (which was replaced by the Old Loan Agreement (as defined below) in October 2016 and the Multidraw Term Loan Agreement in August 2018) prohibiting the Company from declaring or paying dividends on the Series B Preferred Stock, the Company suspended the quarterly cash dividend on the Series B Preferred Stock beginning with the dividend payment due on April 15, 2016. The Old Loan Agreement prohibited, and the Multidraw Term Loan Agreement also prohibited the Company from declaring and paying cash dividends on the Series B Preferred Stock. Under the terms of the Series B Preferred Stock, any unpaid dividends accumulated. As of December 31, 2018, the Company had deferred eleven quarterly dividend payments and had accrued a $14.6 million payable related to the eleven deferred quarterly dividends and the quarterly dividend that accrued through the bankruptcy filing date. The accrued dividend payable is included in liabilities subject to compromise on the consolidated balance sheet.

Mandatory conversion. The Company could, 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 gave the conversion notice equaled or exceeded 130% of the conversion price in effect on each such trading day.

Conversion rights. Each share of Series B Preferred Stock could be converted at any time, at the option of the holder, into 0.8608 shares of the Company’s common stock (which is based on an initial conversion price of approximately $58.08 per share of common stock, subject to further 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 elected 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 would have delivered upon conversion (if any) would be based upon a 20 trading day averaging period.

Upon any conversion, the holder would 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 was equal to $50 divided by the conversion price at the time. The conversion price was subject to adjustment upon the occurrence of certain events.

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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, 2018	Loss(Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(13,919	)	25,581	$	(0.54	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(13,919	)	25,581	$	(0.54	)
For the Year Ended December 31, 2017	Loss(Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(11,776	)	21,330	$	(0.55	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(11,776	)	21,330	$	(0.55	)
For the Year Ended December 31, 2016	Loss(Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(96,245	)	18,354	$	(5.24	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(96,245	)	18,354	$	(5.24	)

An aggregate of 2.0 million, 1.6 million and 0.9 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock for the years ended December 31, 2018, 2017 and 2016, respectively, and common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 1.3 million shares for each of the periods presented were not included in the computation of diluted earnings per share for the years ended December 31, 2018, 2017 and 2016, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for the year.

Note 6—Share-Based Compensation

As discussed in “Note 2-Voluntary Reorganization under Chapter 11 of the Bankruptcy Code”, on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, all of the Predecessor’s common stock (and any share-based compensation based on such common stock) was canceled with the former holders thereof not receiving any consideration in respect thereof. The Predecessor's share-based compensation plan was also terminated on the Effective Date. Accordingly, the following discussion relates solely to the Predecessor’s share-based compensation plan and share-based compensation issued and outstanding prior to such cancellation.    

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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, 2018, 2017 and 2016 is as follows (in thousands):

	Year Ended December 31,
	2018			2017		2016
Stock options:
Incentive Stock Options (share settled)	$	407		$	820	$	206
Non-Qualified Stock Options (share settled)	94			387		164
Restricted stock (share settled)	465			197		1,073
Cash settled stock units	(241		)	245		244
Share-based compensation	$	725		$	1,649	$	1,687

During the years ended December 31, 2017 and 2016, the Company capitalized $103,000 and $106,000, respectively, 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, 2018. During the years ended December 31, 2018, 2017 and 2016, the Company recorded income tax benefits of approximately $101,000, $270,000 and $512,000, respectively, related to share-based compensation expense recognized during those periods. As a result of the adoption of ASU 2016-09 during the year ended December 31, 2017, the Company recognized an additional deferred tax asset of $4.7 million related to net operating loss carryforwards for excess tax benefits on share-based compensation that did not meet the criteria for recognition under previous guidance.

Share-Based compensation settled in shares

At December 31, 2018, the Company had $0.4 million of unrecognized compensation cost related to unvested restricted stock and stock options.

Stock Options

Stock options may be granted to employees and consultants and generally vest ratably over a three-year period. Stock options may also be granted to directors and generally vest one year or less from the date of grant to align with their term on the board. Stock options must be exercised within 10 years of the grant date. The exercise price of each option may not be less than 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 an 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.    

The following table outlines the assumptions used in computing the fair value of stock options granted during 2017 and 2016. No such grants were made during 2018.    

	2017	2016
Dividend yield	—%	—%
Expected volatility	80.44%	62.0%-79.99%
Risk-free rate	1.925%	1.255%-2.09%
Expected term	6 years	6 years
Stock options granted	219,130	1,168,754
Wgtd. avg. grant date fair value per share	$1.28	$1.96
Fair value of grants	$280,000	$2,293,000

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     The following table details stock option activity during the year ended December 31, 2018:

	Number of Options		Wgtd. Avg. Exercise  Price		Wgtd. Avg. Remaining  Life	Aggregate Intrinsic  Value (000’s)
Outstanding at beginning of year	1,608,646		$	6.20
Granted	—		—
Expired/cancelled/forfeited	(121,823	)	4.98
Exercised	—		—
Outstanding at end of year	1,486,823		6.34		7.03	$	—
Options exercisable at end of year	1,047,590		$	7.78	6.64	$	—

The total fair value of stock options that vested during the years ended December 31, 2018, 2017 and 2016 was $1.2 million, $1.6 million and $0.4 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, 2018:

Range of	Options	Wgtd. Avg.	Wgtd. Avg.	Options	Wgtd. Avg.
Exercise	Outstanding	Remaining	Exercise	Exercisable	Exercise
Price	12/31/2018	Contractual Life	Price	12/31/2018	Price
$0.00-$2.37	250,477	8.43	$1.99	105,780	$2.07
$3.17-$4.36	1,013,663	7.68	$3.37	719,127	$3.36
$16.72-$19.52	68,190	4.42	$17.11	68,190	$17.11
$20.40-$30.32	154,493	1.73	$28.15	154,493	$28.15
	1,486,823			1,047,590	$7.78

Restricted Stock

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. Restricted stock granted to employees generally vests ratably over a three-year period. Restricted stock granted to directors vests one year or less 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.

The following table details restricted stock activity during the year ended December 31, 2018:

	Number of Shares		Wgtd. Avg. Fair Value  per Share
Outstanding at beginning of year	487,502		$1.87
Cancelled/forfeited	(34,946	)	$1.85
Lapse of restrictions	(37,500	)	$2.15
Outstanding at December 31, 2018	415,056		$1.85

The weighted average grant date fair value of restricted stock granted during the year ended December 31, 2017 was $1.87 per share. No restricted stock was granted in 2018 and 2016. The total fair value of restricted stock that vested during the years ended December 31, 2018, 2017 and 2016 was $0.1 million, $1.3 million and $2.4 million, respectively.

Share-Based compensation settled in cash

Restricted Stock Units

The Company may grant restricted stock units ("RSUs") to employees that vest ratably 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

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rendered at the reporting date. During 2018 and 2017, the Company paid $24,000 and $59,000, respectively, to settle 323,374 and 31,703 RSUs, respectively, that vested during the period.

Market Based Restricted Stock Units

The Company granted 60,767 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 2014 MRSUs vested 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. In November 2017, the Company granted an additional 270,269 MRSUs. The performance period ended on December 31, 2018 for these grants and executive officers earned none of the MRSUs. 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 stock prices of the Company and its peer group, a risk-free interest rate, and an estimated volatility for the Company and its peer group. As of December 31, 2018, the Company had no liability for RSUs outstanding and as of December 31, 2017, the Company had a liability for RSUs and MRSUs outstanding in the amount of $0.3 million, based upon the closing stock price at December 31, 2018 and December 31, 2017, respectively.

The following table details MRSU and RSU activity during the year ended December 31, 2018:

	MRSU		RSU		Total
Outstanding at beginning of year	277,733		889,587		1,167,320
Granted	—		—		—
Expired/Cancelled/Forfeited	(270,269	)	(78,808	)	(349,077	)
Vested/Paid	(7,464	)	(323,374	)	(330,838	)
Outstanding at December 31, 2018	—		487,405		487,405

Note 7—Asset Retirement Obligation

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 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 summarizes the changes to the Company’s asset retirement obligation (in thousands):

	Year Ended December 31,
	2018			2017
Asset retirement obligation, beginning of period	$	31,310		$	36,610
Liabilities incurred	7			574
Liabilities settled	(863		)	(3,364		)
Accretion expense	322			2,252
Revisions in estimated cash flows	(62		)	(4,514		)
Divestiture of oil and gas properties	(28,234		)	(248		)
Asset retirement obligation, end of period	2,480			31,310
Less: current portion of asset retirement obligation	(183		)	(687		)
Long-term asset retirement obligation	$	2,297		$	30,623

Divestitures of oil and gas properties during 2018 included $28.2 million as a result of the sale of the Company's Gulf of Mexico assets in January 2018. The liabilities incurred, revisions in estimated cash flows and divestitures represent non-cash investing activities for purposes of the statement of cash flows.

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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, 2017, all of the Company's outstanding derivative instruments were designated as cash flow hedges. The Company had no outstanding derivative contracts as of December 31, 2018.

Oil and gas sales include additions related to the settlement of gas hedges of $0.8 million, $1.5 million and $1.8 million, for the years ended December 31, 2018, 2017 and 2016, respectively. Oil and gas sales include reductions of $1.4 million related to the settlement of oil hedges for the year ended December 31, 2018. There were no settlements of Ngls for any period presented or oil hedges for the years ended December 31, 2017 and 2016. On June 14, 2018, the Company's hedging counterparty, Koch Supply & Trading LP, terminated the only outstanding hedge contract resulting in a settlement of $0.5 million. The settlement at the termination date remained in accumulated other comprehensive loss and was reclassified to earnings as the hedged volumes were produced over the original term of the contract.

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, 2017:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
December 31, 2017	Derivative asset	$	1,174
December 31, 2017	Derivative liability	$	(731	)

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for years ended December 31, 2018, 2017 and 2016:

Instrument	Amount of Gain (Loss) Recognized in Other Comprehensive Income			Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into Income
Commodity Derivatives at December 31, 2018	$	(990	)	Oil and gas sales	$	(622	)
Commodity Derivatives at December 31, 2017	$	6,654		Oil and gas sales	$	1,461
Commodity Derivatives at December 31, 2016	$	(4,447	)	Oil and gas sales	$	1,811

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, 2017 were in the form of swaps based on NYMEX pricing for oil and natural gas. The

fair value of these derivatives was 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 designated its commodity derivatives as Level 2 in the fair value hierarchy. The Company had no outstanding derivative contracts at December 31, 2018.

The following table summarizes the Company’s assets (liabilities) that are subject to fair value measurement on a recurring basis as of December 31, 2017 (in thousands):

	Fair Value Measurements Using
Instrument	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity Derivatives:
At December 31, 2017	$	—	$	443	$	—

The fair value of the Company's cash and cash equivalents approximated book value at December 31, 2018 and 2017. The fair value of the Multidraw Term Loan Agreement approximated face value as of December 31, 2018 and 2017. The fair value of the Company's 2021 Notes and 2021 PIK Notes was determined based upon market quotes provided by an independent broker, which represents a Level 2 input. The fair value of the 2021 Notes was $2.8 million and $7.3 million and the fair value of the 2021 PIK Notes was $82.5 million and $198.7 million as of December 31, 2018 and 2017, respectively.

Note 10—Long-Term Debt

Predecessor Long-Term Debt

On August 19, 2010, the Company issued $150 million in principal amount of its 10% Senior Notes due 2017. On July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (collectively, the "2017 Notes").

On February 17, 2016, the Company closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. In satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the then outstanding aggregate principal amount of 2017 Notes, the Company (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of its new 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately 1.1 million shares of Predecessor common stock. Following the completion of the February Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.

On September 27, 2016, the Company closed private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes and 2021 Notes. In satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the then outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the then outstanding aggregate principal amount of 2021 Notes, the Company issued (i) $243.5 million in aggregate principal amount of its new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately 3.5 million shares of Predecessor common stock. The Company also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including, September 27, 2016. Following the consummation of the September Exchange, there were $22.7 million in aggregate principal amount of the 2017 Notes outstanding and $14.2 million in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes.

On March 31, 2017, the Company redeemed the remaining outstanding 2017 Notes at a redemption price of $22.8 million. The redemption was funded by cash on hand and amounts borrowed under the Old Loan Agreement described below. On December 28, 2017, the Company issued 2.2 million shares of Predecessor common stock to extinguish approximately $4.8 million of outstanding principal amount of 2021 Notes.

The 2021 PIK Notes accrued interest at a rate of 10% per annum on the principal amount and interest was payable semi-annually in arrears on February 15 and August 15 of each year. The Company was permitted, at its option, for the first three interest payment dates of the 2021 PIK Notes, to instead pay interest at (i) the annual rate of 1% in cash plus (ii) the annual rate of 9% PIK (the "PIK Interest") payable by increasing the principal amount outstanding of the 2021 PIK Notes or by issuing additional

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2021 PIK Notes in certificated form. The Company exercised this PIK option in connection with the interest payments due on February 15, 2017, August 15, 2017 and February 15, 2018.

The 2021 Notes accrued interest at a rate of 10% per annum on the principal amount and interest was payable semi-annually in arrears on February 15 and August 15 of each year.

The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to ASC Topic 470-60 "Troubled Debt Restructurings by Debtors." The Company determined that the future undiscounted cash flows from the 2021 PIK Notes issued in the September Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes and the 2021 Notes tendered in the September Exchange. Accordingly, no gain or loss on extinguishment of debt was recognized in connection with the September Exchange. The net shortfall of the remaining carrying value of the 2017 Notes and 2021 Notes tendered as compared to the principal amount of the 2021 PIK Notes issued in the September Exchange of $0.6 million was reflected as part of the carrying value of the 2021 PIK Notes. Such shortfall was being amortized under the effective interest method over the term of the 2021 PIK Notes.

The Company previously determined that the future undiscounted cash flows from the 2021 Notes issued in the February Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the February Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the February Exchange. The excess of the remaining carrying value of the 2017 Notes tendered over the principal amount of the 2021 Notes issued in the February Exchange of $13.9 million was reflected as part of the carrying value of the 2021 Notes. The amount of the excess carrying value attributable to the 2021 Notes tendered in the September Exchange was then reflected as part of the carrying value of the 2021 PIK Notes. The excess carrying value attributable to the remaining 2021 Notes was being amortized under the effective interest method over the term of the 2021 Notes.

On October 17, 2016, the Company entered into a multidraw term loan agreement (the "Old Loan Agreement") with Franklin Custodian Funds - Franklin Income Fund, as a lender, and Wells Fargo Bank, National Association, as administrative agent (the "Agent"), replacing the prior credit agreement with JPMorgan Chase Bank, N.A. Effective August 14, 2018, the Company and certain of its subsidiaries entered into a Forbearance Agreement (the "Forbearance Agreement") with the Agent for the lenders with respect to the Old Loan Agreement. Pursuant to the Forbearance Agreement, the Agent and the lenders under the Old Loan Agreement agreed to forbear from taking any action with respect to certain specified events of default occurring under the Old Loan Agreement as a result of non-payment by the Company of interest with respect to the 2021 PIK Notes and 2021 Notes when due and payable on August 15, 2018 under the indentures governing those notes. On August 31, 2018, the Company and PetroQuest Energy, L.L.C. entered into a new Multidraw Term Loan Agreement (the "Multidraw Term Loan Agreement"), which replaced the Old Loan Agreement with the lenders party thereto from time to time (the "Lenders") and the Agent. The Multidraw Term Loan Agreement provided a multi-advance term loan facility in the principal amount of up to $50.0 million. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) were permitted to be used to repay existing debt, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes. On August 31, 2018, the Company borrowed $50.0 million under the Term Loans, and repaid $32.5 million of outstanding borrowings under the Old Loan Agreement, plus accrued interest and fees, and retained the balance of the borrowings for general corporate purposes. As of December 31, 2018, the Company had no borrowing availability under the Multidraw Term Loan Agreement.

Effective September 14, 2018, the Company and certain of its subsidiaries entered into a Forbearance Agreement (the "Loan Forbearance Agreement") with the Agent for the lenders with respect to the Multidraw Term Loan Agreement. Pursuant to the Loan Forbearance Agreement, the Agent and Lenders agreed to forbear from taking any action with respect to certain anticipated events of default occurring under the Multidraw Term Loan Agreement as a result of the non-payment of interest with respect to the 2021 Notes and 2021 PIK Notes when due and payable on August 15, 2018, and such non-payment continuing for a period of 30 days under the indentures governing the notes. The Loan Forbearance Agreement was effective from September 14, 2018 until the earlier of (i) 11:59 p.m. Eastern time on September 28, 2018 or (ii) the occurrence of any specified forbearance default, which includes, among other things, any event of default under the Multidraw Term Loan Agreement other than the anticipated events of default or a breach by the Company or certain of its subsidiaries of the Loan Forbearance Agreement. On September 28, 2018, October 5, 2018, October 19, 2018 and October 31, 2018, the Company and certain of its subsidiaries, the Agent and the Lenders entered into first, second, third and fourth amendments to the Loan Forbearance Agreement that extended the September 28, 2018 deadline to 11:59 p.m. Eastern time on each of October 5, 2018, October 19, 2018, October 31, 2018 and November 6, 2018, respectively. The Loan Forbearance Agreement terminated on the commencement of the Chapter 11 Cases described in Note 2.

Effective September 14, 2018, the Company and certain of its subsidiaries entered into (i) a Forbearance Agreement (the "2021 Notes Forbearance Agreement") with certain holders (the "2021 Notes Supporting Holders") of approximately $7.3 million in aggregate principal amount (representing approximately 77.9% of the outstanding principal amount) of the 2021 Notes, and (ii) a Forbearance Agreement (the "2021 PIK Notes Forbearance Agreement" and together with the 2021 Notes Forbearance

F-19

Agreement, the "Notes Forbearance Agreements") with certain holders (the "2021 PIK Notes Supporting Holders" and together with the 2021 Notes Supporting Holders, the "Supporting Holders") of approximately $194.6 million in aggregate principal amount (representing approximately 70.7% of the outstanding principal amount) of the 2021 PIK Notes.

Pursuant to the Notes Forbearance Agreements, the Supporting Holders agreed to forbear from exercising their rights and remedies under their respective indentures governing the 2021 Notes and the 2021 PIK Notes or the related security documents with respect to certain anticipated events of default occurring under the indentures as a result of the non-payment by the Company of interest with respect to the 2021 Notes and the 2021 PIK Notes when due and payable on August 15, 2018 and such non-payment continuing for a period of 30 days, until the earlier of (i) 11:59 p.m. Eastern time on September 28, 2018 and (ii) the date the Notes Forbearance Agreements otherwise terminate in accordance with the terms therein (the "Forbearance Period"). Pursuant to the Notes Forbearance Agreements, the Supporting Holders agreed to not deliver any notice or instruction in respect of the exercise of any of the rights and remedies otherwise available under the indentures or the related security documents with respect to such anticipated events of default. The Supporting Holders also agreed to not transfer any ownership in the 2021 Notes and the 2021 PIK Notes held by any of the Supporting Holders during the Forbearance Period other than to potential transferees currently parties to, or who agree in writing to be bound by, the Notes Forbearance Agreements. On September 28,2018, October 5, 2018, October 19, 2018 and October 31, 2018, the Company and certain of its subsidiaries, and the Supporting Holders entered into first, second, third and fourth amendments to the Notes Forbearance Agreements that extended the September 28, 2018 deadline to 11:59 p.m. Eastern time on each of October 5, 2018, October 19, 2018, October 31, 2018 and November 6, 2018, respectively. The Notes Forbearance Agreements terminated on the commencement of the Chapter 11 Cases described in Note 2.

The face value of the 2021 Notes and the 2021 PIK Notes, including accrued PIK interest, is classified as liabilities subject to compromise as of December 31, 2018. The Term Loans are reflected net of $0.3 million and $2.0 million of related unamortized deferred financing costs as of December 31, 2018 and 2017, respectively. The adjustments to write off the remaining unamortized deferred financing costs and carrying value adjustments related to the February Exchange and September Exchange are included in reorganization items in the consolidated statement of operations.

Successor Long-Term Debt

On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Company entered into the Term Loan Agreement (the “Exit Facility”) with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent. The Exit Facility provides for a $50 million term loan facility.

The proceeds of the Exit Facility were used to repay in full the loans and other obligations under the Multidraw Term Loan Agreement. The maturity date of the Exit Facility is November 8, 2023. The interest rate per annum is equal to (i) in the case of LIBOR Loans (as defined in the Exit Facility), 7.5% per annum and (ii) in the case of Base Rate Loans (as defined in the Exit Facility), 6.5% per annum. The Exit Facility is secured by a first priority lien on substantially all of the Company's assets.

The Company is subject to a restrictive covenant under the Exit Facility, consisting of maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of its oil and gas properties, before any state, federal, foreign or other income taxes, attributable to total proved reserves, using strip prices then in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the aggregate outstanding principal amount of the term loans to be less than 1.50 to 1.00 as measured on the last day of each calendar. If the Company fails to maintain the ratio, it may either (i) prepay the outstanding term loans such that after giving effect to such prepayment, the financial covenant is met or (ii) be in default under the Exit Facility, in which case the term loans and all other amounts owed pursuant to the Exit Facility would become immediately due and payable.

The Exit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, entering into mergers, consolidations and sales of assets, and transactions with affiliates and other customary covenants.

The Exit Facility contains customary events of default and remedies for credit facilities of this nature. If the Company does not comply with the financial and other covenants in the Exit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Exit Facility. An event of default under the Exit Facility, if not cured or waived, could result in an event of default under the 2024 PIK Notes (as defined below).

On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Company entered into an indenture (the “Indenture”) with Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral agent, and issued $80 million of its new 10% Senior Secured PIK Notes due 2024 (the “2024 PIK Notes”) pursuant thereto.

F-20

Interest on the 2024 PIK Notes accrues at a rate of 10% per annum payable semi-annually in kind (“PIK Interest”) on February 15 and August 15 of each year, beginning on August 15, 2019. At the election of the Board of Directors, so long as the Company has provided notice to the holders of the 2024 PIK Notes and the Trustee of such election at least 30 days prior to any applicable interest payment date, interest on the 2024 PIK Notes for any interest period may instead be payable at the annual rate (i) solely in cash (the “Cash Interest”) or (ii) partially as Cash Interest and partially as PIK Interest. The maturity date of the 2024 Notes is February 15, 2024. The 2024 PIK Notes are secured on a second priority lien basis by the equity of the Company's subsidiary PetroQuest Energy, LLC that also secures the Exit Facility. Pursuant to the terms of an intercreditor agreement, the security interest in those assets that secure the 2024 PIK Notes and the related guarantee will be contractually subordinated to liens thereon that secure the Exit Facility and certain other permitted obligations as set forth in the Indenture. Consequently, the 2024 PIK Notes and the related guarantee will be effectively subordinated to the Exit Facility and such other permitted obligations to the extent of the value of such assets.

The Company may, at its option, on any one or more occasions redeem all or a portion of the 2024 PIK Notes issued under the Indenture at the redemption prices set forth below (expressed in percentages of principal amount on the redemption date), plus accrued and unpaid Cash Interest together with an amount of cash equal to all accrued and unpaid PIK Interest on the 2024 PIK Notes to be redeemed to, but not including, the redemption date (subject to the right of holders of the 2024 PIK Notes of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the periods set forth below:

PeriodRedemption Price

February 8, 2019 to February 7, 2020        102.000%

February 8, 2020 to February 7, 2021        101.000%

February 8, 2021 and thereafter            100.000%

Upon the occurrence of certain change of control events, any holder of the 2024 PIK Notes will have the right to cause the Company to repurchase all or any part of such holder’s 2024 PIK Notes at a repurchase price payable in cash equal to 101% of the principal amount of the 2024 PIK Notes to be repurchased (including any PIK Notes (as defined in the Indenture) or any increase in principal amount of the 2024 PIK Notes in connection with PIK Interest, plus accrued interest to the date of repurchase (subject to the right of holders of record on the relevant record date to receive interest due on the related interest payment date).

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 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.

During 2018, 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 $0 and $20,000, respectively. During 2017, 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 $(107,000) and $41,000, respectively. During 2016, 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 $(15,000) and $25,000, respectively. 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, 2018, the Company’s joint interest billing receivable included no amounts due from the related parties discussed above or their affiliates, attributable to their share of costs.

In December 2017, the Company sold certain saltwater disposal assets in East Texas to a third party purchaser. In connection with the sale, the Company also entered into a volumetric commitment to deliver saltwater volumes to the purchaser of the saltwater disposal assets over a six year period. One of the minority owners of the purchaser is the son of Dr. Charles Mitchell, II, a member of our Predecessor's board of directors. The transactions were approved by the Predecessor's Audit Committee.    

F-21

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, 2016, 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 $2.51 per Mcf of natural gas, $40.85 per barrel of oil and $1.82 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 $40.3 million during the year ended December 31, 2016. The Company’s cash flow hedges in place decreased these ceiling test write-downs by approximately $8.0 million for the year ended December 31, 2016. The Company did not recognize a ceiling test write-down during the years ended December 31, 2018 and 2017.

Note 13—Other Comprehensive Income (Loss)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2016 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2015	$	947		$	—		$	947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	(4,447		)	—			(4,447		)
Income tax effect	1,654			(1,654		)	—
Net of tax	(2,793		)	(1,654		)	(4,447		)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(1,811		)	—			(1,811		)
Income tax effect	674			(113		)	561
Net of tax	(1,137		)	(113		)	(1,250		)
Net other comprehensive loss	(3,930		)	(1,767		)	(5,697		)
Balance as of December 31, 2016	$	(2,983	)	$	(1,767	)	$	(4,750	)

F-22

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2017 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2016	$	(2,983	)	$	(1,767	)	$	(4,750	)
Other comprehensive income before reclassifications:				—
Change in fair value of derivatives	6,654			—			6,654
Income tax effect	(2,475		)	1,767			(708		)
Net of tax	4,179			1,767			5,946
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(1,461		)	—			(1,461		)
Income tax effect	543			—			543
Net of tax	(918		)	—			(918		)
Net other comprehensive loss	$	3,261		$	1,767		$	5,028
Balance as of December 31, 2017	$	278		$	—		$	278

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2018 (in thousands):        

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2017	$	278
Other comprehensive income before reclassifications:
Change in fair value of derivatives	(990		)
Income tax effect	238
Net of tax	(752		)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	622
Income tax effect	(148		)
Net of tax	474
Net other comprehensive loss	(278		)
Balance as of December 31, 2018	$	—

Note 14—Income Taxes

The Company typically provides for income taxes at the statutory federal income tax rate 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 three-year cumulative 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, of which there were none as of December 31, 2018. The Company had a valuation allowance of $118.7 million as of December 31, 2018 and $115.9 million as of December 31, 2017.

The Tax Cuts and Jobs Act (the “Act”) was enacted on December 22, 2017. The Act, among other things, reduces the U.S. federal corporate tax rate from 35% to 21%, eliminates the corporate alternative minimum tax and changes how existing alternative minimum tax credits are realized, creates a new limitation on deductible interest expense and changes the rules related to uses and limitations of net operating loss carryforwards generated in tax years beginning after December 31, 2017. The Company made a reasonable estimate of the effects on its existing deferred tax balances and recognized a provisional amount of $64.9 million

F-23

as of December 31, 2017 to remeasure deferred tax assets and liabilities based on the rate at which they are expected to reverse in the future, which is generally 21%. This amount was included as a component of income tax expense (benefit) from continuing operations and was fully offset by the related adjustment to the Company’s valuation allowance. The Company finalized its accounting for the Act in connection with the filing of its 2017 federal tax return and determined no adjustment was necessary to the previously recognized provisional amount.

As a result of the adoption of ASU 2016-09 during the year ended December 31, 2017, the Company recognized an additional deferred tax asset of $4.7 million related to net operating loss carryforwards for excess tax benefits on share-based compensation that did not meet the criteria for recognition under previous guidance. This additional deferred tax asset was fully offset by the related adjustment to the Company's valuation allowance. The cumulative effect adjustment to record the previously unrecognized excess tax benefits and the related adjustment to the valuation allowance, were recorded in retained earnings on the date of adoption.

An analysis of the Company’s deferred tax assets and liabilities follows (amounts in thousands):

	December 31,
	2018			2017
Net operating loss carryforwards	$	86,046		$	78,541
Percentage depletion carryforward	6,011			5,701
Interest expense carryforward	10,540			—
Contributions carryforward and other	194			192
Temporary differences:
Oil and gas properties	3,673			8,279
Asset retirement obligation	602			7,602
Derivatives	—			(107		)
Share-based compensation	1,403			1,269
Original issue discount on debt exchanges	9,815			14,429
Other	432			—
Valuation allowance	(118,716		)	(115,906		)
Deferred tax asset (liability)	$	—		$	—

At December 31, 2018, the Company had approximately $355.4 million of federal net operating loss carryforwards. If not utilized, approximately $6.9 million of such carryforwards would expire in 2025, $328.2 million would expire by the year 2037 and $20.3 million does not expire and is subject to a limitation of 80% of taxable income. The Company also had approximately $180.7 million of Louisiana state net operating loss carryforwards as of December 31, 2018. If not utilized, approximately $0.3 million of such carryforwards would expire during 2019 and the remainder would expire by the year 2038. The Company has available for tax reporting purposes $28.2 million in statutory depletion deductions that may be carried forward indefinitely. The Company had approximately $43.9 million of carryforwards related to the limitation on deductible interest expense. The interest expense carryforward does not expire and is subject to a limitation of 30% of adjusted taxable income.

F-24

Income tax expense (benefit) for each of the years ended December 31, 2018, 2017 and 2016 was different than the amount computed using the federal statutory rate (21%) for the following reasons (amounts in thousands):

	For the Year Ended December 31,
	2018			2017			2016
Amount computed using the statutory rate	$	(1,973	)	$	(2,655	)	$	(31,623	)
Increase (reduction) in taxes resulting from:
Impact of rate change on deferred tax	—			64,915			—
State & local taxes	(1,731		)	(368		)	(2,000		)
Percentage depletion carryforward	(256		)	(66		)	(163		)
Non-deductible stock option expense (1)	98			305			77
Share-based compensation (2)	—			64			707
Restructuring costs	1,528			—			—
Other	93			(21		)	1,415
Change in valuation allowance	2,393			(63,123		)	32,130
Income tax expense (benefit)	$	152		$	(949	)	$	543

(1) Relates to compensation expense related to 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 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. Although we cannot predict the outcome of these proceedings with certainty, management believes that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material adverse effect on the Company's business or financial position.

The commencement of the Chapter 11 Cases automatically stayed litigation and claims that were or could have been brought prior to November 6, 2018. The claims related to two class action lawsuits filed in October 2016 will be treated as general unsecured claims with a maximum amount that may be distributed to the holders of such claims not to exceed $400,000 under the Plan.

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, 2018 under these operating leases are as follows (in thousands):

2019	$	1,240
2020	1,173
2021	445
2022	431
2023	392
Thereafter	—
	$	3,681

Total rent expense under operating leases was approximately $1.5 million for each of 2018, 2017 and 2016, respectively.

Subsequent to December 31, 2018 and as part of the Chapter 11 Cases, the Company entered into a lease amendment with regard to its office space in The Woodlands, Texas, which reduced the above noted lease commitments by $1.3 million thru 2022.

F-25

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)

	For the Year-Ended December 31,
	2018			2017			2016
Acquisition costs:
Proved	$	241		$	1,330		$	3,346
Unproved (1)	6,190			12,762			2,197
Divestiture of proved leasehold	(2,604		)	(4,795		)	(7,000		)
Exploration costs:
Proved	(51		)	9,466			715
Unproved	233			(287		)	603
Development costs (2)	(18,928		)	32,622			1,522
Capitalized general and administrative and interest costs	8,070			8,269			7,558
Total costs incurred	$	(6,849	)	$	59,367		$	8,941

	For the Year-Ended December 31,
	2018			2017			2016
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	$	(1,285,660	)	$	(1,243,286	)	$	(1,157,455	)
Provision for DD&A	(22,410		)	(31,667		)	(27,962		)
Ceiling test writedown	—			—			(40,304		)
Sale of proved properties and other (3)	6,478			(10,707		)	(17,565		)
Balance, end of year	$	(1,301,592	)	$	(1,285,660	)	$	(1,243,286	)
DD&A per Mcfe	$	1.05		$	1.15		$	1.19

(1) During 2017, the Company acquired approximately 24,600 gross acres for approximately $9.3 million in cash and 2.0 million shares of common stock. In total for 2017 and 2018, the Company has invested approximately $15.0 million in leasing costs and geological and engineering data.

(2) During 2018, the Company sold its Gulf of Mexico properties and removed approximately $28.2 million of future discounted asset retirement obligations, which was recorded as a reduction in the capitalized costs of oil and gas properties.

(3) During 2018, the Company sold its Gulf of Mexico properties, receiving no cash consideration and funding amounts related to the future abandonment costs for the properties and purchase price adjustments. During 2017, the Company sold its East Lake Verret assets for net proceeds of approximately $2.2 million and its East Texas saltwater disposal assets for net proceeds of $8.5 million. During 2016, the Company sold its remaining Oklahoma producing assets for net proceeds of $17.6 million.

At December 31, 2018 and 2017, unevaluated oil and gas properties totaled $23.5 million and $21.9 million, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2018 included $0.9 million of costs related to wells in progress at year-end. At December 31, 2017, unevaluated costs included $0.7 million related to two facilities in progress at year-end, which were transferred to evaluated oil and gas properties during 2018. The Company capitalized $1.8 million, $1.6 million and $0.9 million of interest during 2018, 2017 and 2016, respectively. Of the total unevaluated oil and gas property costs of $23.5 million at December 31, 2018, $7.4 million, or 32%, was incurred in 2018, $13.9 million, or 59%, was incurred in 2017 and $2.2 million, or 9%, was incurred in prior years. In connection with the sale of the Company's Gulf of Mexico assets, approximately

F-26

$5.5 million, or 25% of the total unevaluated balance at December 31, 2017, was transferred to evaluated oil and gas properties in 2018. Of the remaining unevaluated balance at December 31, 2018, the Company expects the majority of the costs will be evaluated within the next three years, including $2.7 million expected to be evaluated during 2019.

Oil and Gas Reserve Information

The Company’s net proved oil and gas reserves at December 31, 2018 have been estimated by independent petroleum engineers in accordance with guidelines established by the SEC using a historical 12-month, first of 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-27

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:

	Oil in MBbls		NGL in MMcfe		Natural Gas in MMcf		Total Reserves in MMcfe
Proved reserves as of December 31, 2015	1,806		34,826		132,344		178,004
Revisions of previous estimates	247		(4,380	)	(11,854	)	(14,748	)
Extensions, discoveries and other additions	—		—		1,485		1,485
Sale of reserves in place	(154	)	—		(24,834	)	(25,759	)
Production	(502	)	(3,871	)	(16,617	)	(23,501	)
Proved reserves as of December 31, 2016	1,397		26,575		80,524		115,481
Revisions of previous estimates	308		(7,269	)	381		(5,040	)
Extensions, discoveries and other additions	777		4,565		64,704		73,931
Purchase of producing properties	48		—		473		761
Sale of reserves in place	(90	)	—		(1,033	)	(1,573	)
Production	(592	)	(4,450	)	(19,611	)	(27,613	)
Proved reserves as of December 31, 2017	1,848		19,421		125,438		155,947
Revisions of previous estimates	130		(1,469	)	2,737		2,044
Extensions, discoveries and other additions	41		2,929		7,947		11,121
Sale of reserves in place	(507	)	(486	)	(13,945	)	(17,472	)
Production	(326	)	(3,373	)	(16,013	)	(21,335	)
Proved reserves as of December 31, 2018	1,186		17,022		106,164		130,305
Proved developed reserves
As of December 31, 2016	1,212		13,073		47,349		67,694
As of December 31, 2017	1,078		12,564		57,409		76,441
As of December 31, 2018	567		10,220		47,516		61,143
Proved undeveloped reserves
As of December 31, 2016	185		13,502		33,175		47,787
As of December 31, 2017	770		6,857		68,029		79,506
As of December 31, 2018	619		6,802		58,648		69,162

Year Ended December 31, 2018

During 2018, the Company’s estimated proved reserves decreased by 16%. The decrease in reserves was the result of 10.1 Bcfe removed as a result of the sale of our Gulf of Mexico assets in January 2018 and 7.3 Bcfe removed due to the selldown of certain of our PUDs in East Texas. Partially offsetting these decreases was an increase of 11.1 Bcfe of PUD reserves from third party drilling as well as the Company's leasing efforts in East Texas. Overall, the Company had a 100% drilling success rate on two wells completed during 2018.

F-28

Year Ended December 31, 2017

During 2017, the Company’s estimated proved reserves increased by 35%. The increase in reserves was the result of 73.9 Bcfe added due to the Company's drilling program in East Texas where it drilled eight gross wells during 2017. In response to low ethane prices, during 2017 the Company elected to bypass ethane processing on a portion of its East Texas production. As a result, the Company reduced its estimated proved ngl reserves to reflect the assumption that ethane would continue to not be recovered as natural gas liquids. Overall, the Company had a 100% drilling success rate during 2017.

Year Ended December 31, 2016

During 2016, the Company's estimated proved reserves decreased by 35% primarily due to the divestiture of the Company's remaining Oklahoma assets and significant reductions in capital spending during 2016. Extensions, discoveries and other additions of 1.5 Bcfe were primarily due to the successful completion of the Company's final Oklahoma wells. Revisions of previous estimates included the reclassification of certain PUD reserves to probable reserves as a result of the Company's assessment of the timing of development. Overall, the Company had a 100% drilling success rate during 2016 on 5 gross wells drilled.

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

	December 31,
	2018			2017			2016
Future cash flows	$	482,766		$	539,244		$	299,035
Future production costs	(171,999		)	(184,171		)	(117,283		)
Future development costs	(73,258		)	(128,447		)	(83,720		)
Future income taxes	—			—			—
Future net cash flows	237,509			226,626			98,032
10% annual discount	(113,484		)	(99,329		)	(30,763		)
Standardized measure of discounted future net cash flows	$	124,025		$	127,297		$	67,269

Changes in Standardized Measure

	Year Ended December 31,
	2018			2017			2016
Standardized measure at beginning of year	$	127,297		$	67,269		$	127,685
Sales and transfers of oil and gas produced, net of production costs	(64,148		)	(70,362		)	(35,993		)
Changes in price, net of future production costs	18,542			53,516			(30,427		)
Extensions and discoveries, net of future production and development costs	2,983			50,977			864
Changes in estimated future development costs, net of development costs incurred during this period	16,241			17,144			26,356
Revisions of quantity estimates	2,755			(7,482		)	(14,889		)
Accretion of discount	12,730			6,727			12,769
Purchase of reserves in place	—			549			—
Sale of reserves in place	1,614			(1,305		)	(16,701		)
Changes in production rates (timing) and other	6,011			10,264			(2,395		)
Net increase (decrease) in standardized measure	(3,272		)	60,028			(60,416		)
Standardized measure at end of year	$	124,025		$	127,297		$	67,269

F-29

The historical twelve-month, first day of the month, average prices of oil, gas and natural gas liquids used in determining standardized measure were:

	2018	2017	2016
Oil, $/Bbl	$68.71	$52.49	$40.85
Ngls, $/Mcfe	4.08	3.23	2.40
Natural Gas, $/Mcf	3.13	3.03	1.82

Note 17 - Summarized Quarterly Financial Information - Unaudited

Summarized quarterly financial information is as follows (amounts in thousands except per share data):

	Quarter Ended
	March 31			June 30			September 30			December 31
2018
Revenues	$	24,917		$	21,507		$	20,886		$	19,789
Income (loss) from operations	(821		)	(1,326		)	(3,657		)	701
Loss available to common stockholders	(2,212		)	(2,611		)	(4,979		)	$	(4,117	)
Loss per share:
Basic	$	(0.09	)	$	(0.10	)	$	(0.19	)	$	(0.16	)
Diluted	$	(0.09	)	$	(0.10	)	$	(0.19	)	$	(0.16	)
2017
Revenues	$	20,772		$	24,251		$	28,184		$	35,080
Income (loss) from operations	(3,633		)	(2,289		)	(1,885		)	221
Loss available to common stockholders	(4,918		)	(3,385		)	(3,085		)	(389		)
Loss per share:
Basic	$	(0.23	)	$	(0.16	)	$	(0.15	)	$	(0.02	)
Diluted	$	(0.23	)	$	(0.16	)	$	(0.15	)	$	(0.02	)

F-30

EX-21.1

Exhibit 21.1 – Subsidiaries of PetroQuest Energy, Inc.

NameJurisdiction

PetroQuest Energy, L.L.C.¹                        Louisiana

PetroQuest Oil and Gas, L.L.C.¹                    Louisiana

TDC Energy LLC¹                            Louisiana

Pittrans, Inc.²                                Oklahoma

Sea Harvester Energy Development Company, L.L.C.³        Louisiana

¹ 100% owned by PetroQuest Energy, Inc.

² 100% owned by PetroQuest Energy, Inc.

³ 92% owned by TDC Energy LLC

EX-23.1

EXHIBIT 23.1

CONSENT OF RYDER SCOTT COMPANY, L.P.

We hereby consent to (i) the inclusion of our reserve report relating to certain estimated quantities of the proved reserves of oil and gas, future net income and discounted future net income, effective December 31, 2018 of PetroQuest Energy, Inc. (the “Company”) in this Annual Report on Form 10-K prepared by the Company for the year ending December 31, 2018, filed as Exhibit 99.1 of the Form 10-K, and (ii) the incorporation by reference in this Annual Report on Form 10-K prepared by the Company for the year ending December 31, 2018, of information contained in our report relating to certain estimated quantities of the Company’s proved reserves of oil and gas, future net income and discounted future net income, effective December 31, 2018. We further consent to references to our firm under the headings “Business and Properties Items - Oil and Gas Reserves” and “Risk Factors,” and included in or made a part of the Annual Report on Form 10-K prepared by the Company for the year ended December 31, 2018.

We further wish to advise that we are not employed on a contingent basis and that at the time of the preparation of our report, as well as at present, neither Ryder Scott Company, L.P. nor any of its employees had, or now has, a substantial interest in PetroQuest Energy, Inc. or any of its subsidiaries, as a holder of its securities, promoter, underwriter, voting trustee, director, officer or employee.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

March 28, 2019

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

EX-31.1

EXHIBIT 31.1

I, Charles T. Goodson, certify that:

1. I have reviewed this Form 10-K of PetroQuest Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the

Exhibit 31.1

audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

_/s/ Charles T. Goodson___

Charles T. Goodson

Chief Executive Officer

March 28, 2019

Exhibit 31.1    2

EX-31.2

EXHIBIT 31.2

I, J. Bond Clement, certify that:

1. I have reviewed this Form 10-K of PetroQuest Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the

Exhibit 31.2

audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ J. Bond Clement

J. Bond Clement

Chief Financial Officer

March 28, 2019

Exhibit 31.2    2

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of PetroQuest Energy, Inc.(the “Company”) on Form 10-K for the year ending December 31, 2018 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Charles T. Goodson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1.    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/Charles T. Goodson

Charles T. Goodson

Chief Executive Officer

March 28, 2019

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.            

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of PetroQuest Energy, Inc.(the “Company”) on Form 10-K for the year ending December 31, 2018 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, J. Bond Clement, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1.    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ J. Bond Clement

J. Bond Clement

Chief Financial Officer

March 28, 2019

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.                                    

EX-99.1

XXX Company

Date

Page 1

PETROQUEST ENERGY, INC.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2018

\s\ James F. Latham

James F. Latham, P.E.

TBPE License No. 49586

Advising Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

January 29, 2019

PetroQuest Energy, Inc.

400 East Kaliste Saloom Rd, Suite 6000

Lafayette, Louisiana 70508

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of PetroQuest Energy, Inc. (PetroQuest) as of December 31, 2018. The subject properties are located in the states of Louisiana and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 11, 2019 and presented herein, was prepared for public disclosure by PetroQuest in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of PetroQuest as of December 31, 2018.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2018, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

SUITE 800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

PetroQuest Energy, Inc.

January 29, 2019

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

PetroQuest Energy, Inc.

As of December 31, 2018

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Reserves
Oil/Condensate – Barrels	562,258		5,447		618,734		1,186,439
Plant Products – Barrels	1,638,456		64,980		1,133,629		2,837,065
Gas – MMcf	46,459		1,057		58,648		106,164
Income Data
Future Gross Revenue		$211,377,639		$4,636,415		$241,970,464		$457,984,518
Deductions	80,640,207		3,465,677		136,369,037		220,474,921
Future Net Income (FNI)		$130,737,432		$1,170,738		$105,601,427		$237,509,597
Discounted FNI @ 10%	$	86,654,490	$	888,241	$	36,482,354		$124,025,085

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software packagePHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. This program was used at the request of PetroQuest. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one-line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. “Other” deductions shown in the cashflows consist of transportation, compression and processing costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Gas reserves account for approximately 69 percent and liquid hydrocarbon reserves account for the remaining 31 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

January 29, 2019

Page 3

	Discounted Future Net Income
	As of December 31, 2018
Discount Rate		Total
Percent		Proved
5		$163,532,396
15		$100,080,455
20		$84,184,361
30		$64,508,489

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes included herein do not include volumes of gas consumed in operations as reserves.

Reserves are “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.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At PetroQuest’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “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.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

January 29, 2019

Page 4

may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

PetroQuest’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which PetroQuest owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

January 29, 2019

Page 5

changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy or a combination of methods. Approximately 59 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis or material balance methods that utilized extrapolations of historical production and pressure data available through December 2018 in those cases where such data were considered definitive. The data utilized in this analysis were furnished to Ryder Scott by PetroQuest or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 41 percent of the proved producing reserves were estimated by the analogy method or a combination of methods. The data utilized from theanalogues as well as well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the sole use of production performance data as a basis for the reserves estimates was considered to be inappropriate.

Approximately 85 percent of the proved developed non-producing reserves included herein were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by PetroQuest, or which we have obtained from public data sources, available through December 2018. The remaining 15 percent proved developed non-producing reserves were estimated by performance, analogy or a combination of methods.

One hundred percent of undeveloped reserves contained herein were based on analogy. The data utilized from theanalogues were considered appropriate and sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

PetroQuest has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by PetroQuest with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by PetroQuest. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

January 29, 2019

Page 6

included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by PetroQuest. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Ryder Scott determined the above-mentioned average prices in effect on December 31, 2018. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area(s) included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by PetroQuest. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by PetroQuest to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

January 29, 2019

Page 7

total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
	Oil/Condensate	WTI Cushing	$65.56/bbl	$68.71/bbl
United States	NGLs	WTI Cushing	$65.56/bbl	$24.46/bbl
	Gas	Henry Hub	$3.10/MMBTU	$3.13/Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished to us by PetroQuest, and were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by PetroQuest. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells, and include product gathering and transportation expenses, as applicable. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by PetroQuest and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by PetroQuest were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with PetroQuest’s plans to develop these reserves as of December 31, 2018. The implementation of PetroQuest’s development plans as presented to us and incorporated herein is subject to the approval process adopted by PetroQuest’s management. As the result of our inquiries during the course of preparing this report, PetroQuest has informed us that the development activities included herein have been subjected to and received the internal approvals required by PetroQuest’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to PetroQuest. PetroQuest has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, PetroQuest has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While PetroQuest’s plans could change from those under existing conditions as of December 31, 2018, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by PetroQuest were held constant throughout the life of the properties.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

January 29, 2019

Page 8

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training.  Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to PetroQuest. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approvingthe evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

January 29, 2019

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by PetroQuest.

PetroQuest makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, PetroQuest has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-8 of PetroQuest, of the references to our name, as well as to the references to our third party report for PetroQuest, which appears in the December 31, 2018 annual report on Form 10-K of PetroQuest. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by PetroQuest.

We have provided PetroQuest with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by PetroQuest and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ James F. Latham

James F. Latham, P.E.

TBPE License No. 49586

Advising Senior Vice President

[SEAL]

JFL (FWZ)/pl

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. James F. Latham was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.

Mr. Latham, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1980, is an Advising Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Latham served in a number of engineering positions with Exxon Company USA (now ExxonMobil). For more information regarding Mr. Latham’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Latham earned a Bachelor of Science degree in Mechanical Engineering from Louisiana Tech University in 1974 and a Master of Science degree in Engineering from Louisiana Tech in 1975. Mr. Latham is a licensed Professional Engineer in the State of Texas (1981) and is also a member of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers.

The Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Latham fulfills. As part of his 2018 continuing education hours, Mr. Latham attended the 2018 RSC Reserves Conference, which addressed such diverse topics as SEC comment letters, application of analytics to unconventional resources, the new SPE-PRMS, and SEC disclosures. Mr. Latham attended additional formalized in-house training during 2018 covering such topics as unconventional resources exploitation and completion practices, decline curve analysis, reservoir mapping, software instruction, and ethics for consultants, among many others. Mr. Latham has personally authored and conducts instruction regarding over 20 petroleum engineering software programs, eleven of which comprise Ryder Scott’s Reservoir Solutions Software for Microsoft^® Excel. Reservoir Solutions Software, published by Ryder Scott, is made available without cost to energy industry professionals, and currently has in excess of 12,500 users located in more than 80 countries worldwide.

Based on his educational background, professional training and more than 40 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Latham has attained the professional qualifications as a Reserves Estimator and as a Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are 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.All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are 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. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

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

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

Document and Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Mar. 10, 2019	Jun. 29, 2018
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	0000872248
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 5,424
Class A Common Stock
Entity Common Stock, Shares Outstanding		9,200,000
Class B Common Stock
Entity Common Stock, Shares Outstanding		1
Class C Common Stock
Entity Common Stock, Shares Outstanding		1

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 34,891	$ 15,655
Revenue receivable	6,364	15,340
Joint interest billing receivable	4,716	6,597
Other receivable	0	7,750
Derivative asset	0	1,174
Deposit for surety bonds	3,550	8,300
Other current assets	3,261	2,125
Total current assets	52,782	56,941
Oil and gas properties:
Oil and gas properties, full cost method	1,361,374	1,369,861
Unevaluated oil and gas properties	23,492	21,854
Accumulated depreciation, depletion and amortization	(1,301,592)	(1,285,660)
Oil and gas properties, net	83,274	106,055
Other property and equipment	9,282	9,353
Accumulated depreciation of other property and equipment	(9,056)	(8,843)
Total property and equipment	83,500	106,565
Other assets	1,005	792
Total assets	137,287	164,298
Current liabilities:
Accounts payable to vendors	11,699	32,148
Advances from co-owners	2,020	1,730
Oil and gas revenue payable	7,765	19,344
Accrued interest	639	1,724
Asset retirement obligation	183	687
Derivative liability	0	731
Other accrued liabilities	1,259	6,476
Total current liabilities	23,565	62,840
Multi-draw Term Loan	49,738	27,963
Asset retirement obligation	2,297	30,623
Preferred stock dividend payable	0	10,278
Other long-term liabilities	0	131
Liabilities Not Subject To Compromise	75,600	413,233
Liabilities subject to compromise	323,854	0
Total liabilities	399,454	413,233
Stockholders’ equity:
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares	1	1
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 25,587 and 25,521 shares, respectively	26	26
Paid-in capital	314,268	313,244
Accumulated other comprehensive income	0	278
Accumulated deficit	(576,462)	(562,484)
Total stockholders’ equity	(262,167)	(248,935)
Total liabilities and stockholders’ equity	137,287	164,298
10% Senior Secured Notes due 2021 | Senior Notes
Current liabilities:
10% Senior Secured Notes	0	9,821
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Current liabilities:
10% Senior Secured Notes	$ 0	$ 271,577

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Preferred stock, par value (usd per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	1,495,000	1,495,000
Preferred stock, shares outstanding	1,495,000	1,495,000
Common stock, par value (usd per share)	$ 0.001	$ 0.001
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	25,587,000	25,521,000
Common stock, shares outstanding	25,587,000	25,521,000
10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate	10.00%	10.00%
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Stated interest rate	10.00%	10.00%

XML

Consolidated Statements of Operations - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Oil and gas sales	$ 87,099,000	$ 108,287,000	$ 66,667,000
Expenses:
Lease operating expenses	20,552,000	33,162,000	28,508,000
Production taxes	3,198,000	3,302,000	354,000
Depreciation, depletion and amortization	22,667,000	32,053,000	28,720,000
Ceiling test write-down	0	0	40,304,000
General and administrative	17,564,000	15,860,000	26,040,000
Accretion of asset retirement obligation	322,000	2,252,000	2,515,000
Interest expense	28,147,000	28,836,000	30,019,000
Total expenses	92,450,000	115,465,000	156,460,000
Other income (expense):
Other income (expense)	248,000	(408,000)	(560,000)
Other income (expense), net	248,000	(408,000)	(560,000)
Loss from operations	(5,103,000)	(7,586,000)	(90,353,000)
Reorganization items	4,293,000	0	0
Income tax expense (benefit)	152,000	(949,000)	543,000
Net loss	(9,548,000)	(6,637,000)	(90,896,000)
Preferred stock dividend	4,371,000	5,139,000	5,349,000
Net loss available to common stockholders	$ (13,919,000)	$ (11,776,000)	$ (96,245,000)
Basic
Net loss per share (in usd per share)	$ (0.54)	$ (0.55)	$ (5.24)
Diluted
Net loss per share (in usd per share)	$ (0.54)	$ (0.55)	$ (5.24)
Weighted average number of common shares:
Basic (shares)	25,581	21,330	18,354
Diluted (shares)	25,581	21,330	18,354

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Consolidated Statements of Comprehensive Loss - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net loss	$ (9,548)	$ (6,637)	$ (90,896)
Change in fair value of derivatives, net of income tax (expense) benefit of $106, ($165) and $561, respectively	(278)	5,028	(5,697)
Comprehensive loss	$ (9,826)	$ (1,609)	$ (96,593)

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Consolidated Statements of Comprehensive Loss (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Income tax (expense) benefit related to other comprehensive income due to derivatives	$ 106	$ (165)	$ 561

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Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows provided by (used in) operating activities:
Net loss	$ (9,548,000)	$ (6,637,000)	$ (90,896,000)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred tax (benefit) expense	152,000	(949,000)	543,000
Depreciation, depletion and amortization	22,667,000	32,053,000	28,720,000
Ceiling test write-down	0	0	40,304,000
Accretion of asset retirement obligation	322,000	2,252,000	2,515,000
Share based compensation expense	966,000	1,447,000	1,444,000
Amortization costs and other	1,138,000	554,000	2,106,000
Non-cash PIK interest	2,961,000	22,895,000	5,722,000
Non-cash reorganization items	534,000	0	0
Gain on asset sale	(863,000)	(3,364,000)	(3,169,000)
Costs incurred to issue 2021 Notes and 2021 PIK Notes	0	0	10,139,000
Gain on extinguishment of debt	0	(403,000)	0
Changes in working capital accounts:
Revenue receivable	8,976,000	(5,046,000)	(3,818,000)
Joint interest billing receivable	2,653,000	610,000	41,400,000
Accounts payable and accrued liabilities	(14,458,000)	2,970,000	(72,760,000)
Advances from co-owners	290,000	(600,000)	(13,788,000)
Net refund (deposit) of surety bonds	4,488,000	(2,037,000)	(6,162,000)
Other	(1,429,000)	408,000	1,102,000
Net cash provided by (used in) operating activities	18,849,000	44,153,000	(56,598,000)
Cash flows used in investing activities:
Investment in oil and gas properties	(20,559,000)	(64,613,000)	(30,366,000)
Investment in other property and equipment	28,000	(54,000)	(24,000)
Sale of oil and gas properties	(6,478,000)	10,707,000	25,482,000
Sale of unevaluated oil and gas properties	7,750,000	0	0
Net cash used in investing activities	(19,259,000)	(53,960,000)	(4,908,000)
Cash flows provided by (used in) financing activities:
Net payments for share based compensation	43,000	(26,000)	11,000
Deferred financing costs	(386,000)	(174,000)	(3,156,000)
Payment of preferred stock dividend	0	0	(1,285,000)
Proceeds from borrowings	52,500,000	20,000,000	10,000,000
Repayment of borrowings	(32,500,000)	0	0
Redemption of 2017 Notes	0	(22,650,000)	(53,626,000)
Costs incurred to issue 2021 Notes and 2021 PIK Notes	0	0	(10,139,000)
Costs incurred to redeem 2021 Notes	(11,000)	0	0
Net cash provided by (used in) financing activities	19,646,000	(2,850,000)	(58,195,000)
Net increase (decrease) in cash and cash equivalents	19,236,000	(12,657,000)	(119,701,000)
Cash and cash equivalents, beginning of period	15,655,000	28,312,000	148,013,000
Cash and cash equivalents, end of period	34,891,000	15,655,000	28,312,000
Cash paid (received) during the period for:
Interest	5,341,000	7,432,000	33,206,000
Income taxes	38,000	(94,000)	(18,000)
Reorganization items	$ 980,000	$ 0	$ 0

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Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Preferred Stock	Paid-In Capital	Other Comprehensive Income (Loss)	Accumulated Deficit
Beginning balance at Dec. 31, 2015	$ (163,067)	$ 16	$ 1	$ 290,432	$ 947	$ (454,463)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of shares in debt exchange	12,525	5		12,520
Retirement of shares upon vesting of restricted stock	(200)	0		(200)
Share-based compensation expense	1,444			1,444
Issuance of shares under employee stock purchase plan	145			145
Derivative fair value adjustment, net of tax	(5,697)				(5,697)
Preferred stock dividend	(5,349)					(5,349)
Net loss	(90,896)					(90,896)
Ending balance at Dec. 31, 2016	(251,095)	21	1	304,341	(4,750)	(550,708)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of shares	7,446	5		7,441
Retirement of shares upon vesting of restricted stock	(10)	0		(10)
Share-based compensation expense	1,447			1,447
Issuance of shares under employee stock purchase plan	25			25
Derivative fair value adjustment, net of tax	5,028				5,028
Preferred stock dividend	(5,139)					(5,139)
Net loss	(6,637)					(6,637)
Ending balance at Dec. 31, 2017	(248,935)	26	1	313,244	278	(562,484)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of shares	(11)	0		(11)
Share-based compensation expense	992			992
Issuance of shares under employee stock purchase plan	43			43
Derivative fair value adjustment, net of tax	(337)				(278)	(59)
Preferred stock dividend	(4,371)					(4,371)
Net loss	(9,548)					(9,548)
Ending balance at Dec. 31, 2018	$ (262,167)	$ 26	$ 1	$ 314,268	$ 0	$ (576,462)

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Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Summary of Significant Accounting Policies

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 an exploration office in The Woodlands, Texas. It is engaged in the exploration, development, acquisition and operation of oil and gas properties in Texas and Louisiana. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to February 8, 2019, and to the pre-emergence company as “Predecessor” for periods prior to February 8, 2019. As discussed in “Note 2-Voluntary Reorganization under Chapter 11 of the Bankruptcy Code” the Company and its wholly owned direct and indirect subsidiaries filed voluntary petitions for bankruptcy relief and subsequently operated as debtors in possession, in accordance with the applicable provisions of the Bankruptcy Code, until emergence on February 8, 2019.

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.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States ("US GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserves and future net cash flows from estimated proved reserves are based on geological and engineering data and depend upon a number of variable factors and assumptions. Changes in estimated proved oil and gas reserves used in the calculation of depreciation, depletion and amortization of oil and gas properties or the present value of the estimated future net cash flows from estimated proved reserves used in the ceiling test could have a material impact on future results of operations.

Bankruptcy Accounting and Financial Reporting

The consolidated financial statements have been prepared in accordance with Accounting Standards Codification ("ASC") 852, Reorganizations, for the period subsequent to the bankruptcy filing. ASC 852 requires that the consolidated financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the Chapter 11 Cases (as defined below) are recorded as reorganization items on the consolidated statement of operations. In addition, the pre-petition obligations that may be impacted by the bankruptcy reorganization process are classified on the consolidated balance sheet in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court (as defined below), even if they may be settled for lesser amounts.

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 twelve-month, first day of the month, average 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.

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 five years.

Deposit For Surety Bonds

The deposit for surety bonds of $3.6 million and $8.3 million at December 31, 2018 and 2017, respectively, represent cash collateral paid with respect to the Company's surety bonds which secured its offshore decommissioning obligations. The Company received a refund of the majority of the remaining deposits during March 2019.

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 that 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 realizability 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 in accordance with Accounting Standards Update ("ASU") 2014-09 "Revenue from Contracts with Customers". 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.

The Company's sources of revenue are oil, natural gas and natural gas liquids ("NGL") production from its oil and gas properties. Oil and natural gas production is typically sold to purchasers through monthly contracts at negotiated sales prices based on published market indices. The sale takes place at the wellhead for oil production and at the wellhead or gas processing plant for natural gas. NGL production is sold once natural gas is processed and the related liquids are removed at the processing plant. The contracts for sale of NGL production are with the processing plant with prices based on what the processing plant is able to receive from third party purchasers.

Sales of oil, natural gas and NGL production are recognized when the product is delivered and title transfers to the purchaser and payment is generally received one to two months after the sale has occurred. The Company had $6.4 million of revenue receivable at December 31, 2018, comprised of $1.1 million of oil revenue, $4.8 million of natural gas revenue and $0.5 million of NGL revenue.

The following table includes a disaggregation of revenue by product including the effects of hedges in place (in thousands):

	Year Ended December 31,
	2018		2017		2016
Total oil sales	$	21,027	$	31,258	$	20,614
Total gas sales	50,768		60,922		37,963
Total ngl sales	15,303		16,107		8,090
Total oil and gas sales	$	87,099	$	108,287	$	66,667

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.

	Year Ended December 31,
	2018	2017	2016
Superior Natural Gas	26%	29%	14%
Shell Trading Company	21%	24%	23%
Texla Energy Management	16%	(a)	(a)
Harvest Pipeline Company	12%	(a)	(a)
Laclede Energy Resources	(a)	(a)	17%
BG Group	(a)	(a)	10%

(a) Less than 10 percent

Derivative Instruments

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 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 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, 2018, the Company had no derivative instruments in place. See Note 8 for further discussion of the Company’s derivative instruments.

Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board ("FASB") issued ASU 2016-02, "Leases (Topic 842)," to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This ASU supersedes the lease requirements in Topic 840, Leases, and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within the Company’s consolidated statements of operations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to mineral leases for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including the first quarter of 2019. The Company will adopt this standard using the modified retrospective method applied to all leases that exist on January 1, 2019. The Company made certain elections allowing it not to reassess contracts that commenced prior to adoption and to not recognize right-of-use assets or lease liabilities for short-term leases. Upon adoption, the Company expects the right-to-use asset and lease liability reported on its consolidated financial statements to be immaterial.

In August 2017, the FASB issued ASU 2017-12, "Derivative and Hedging," to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its consolidated financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. ASU 2017-12 is effective for public entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with earlier application permitted. The Company is currently evaluating the effect that this new standard may have on its consolidated financial statements.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

Divestitures:

On April 17, 2017, the Company completed the sale of its interest in the East Lake Verret field in Louisiana for approximately $2.2 million. On December 15, 2017, the Company completed the sale of its saltwater disposal assets in East Texas for approximately $8.5 million. These sales were accounted for as adjustments to the capitalized costs of oil and gas properties.    

On January 31, 2018, the Company sold its Gulf of Mexico properties. The Company received no consideration from the sale of these properties and was required to contribute approximately $3.8 million towards the future abandonment costs for the properties. As a result of the sale, the Company extinguished approximately $28.2 million of its discounted asset retirement obligations. In connection with the sale, the Company received net cash refunds during 2018 totaling $4.5 million related to a depositary account that served to collateralize a portion of the Company's offshore bonds related to these properties. The Company received the majority of the remaining $3.6 million during March 2019, which is included in deposits for surety bonds on the consolidated balance sheet as of December 31, 2018. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

Acquisitions:

On December 20, 2017, the Company entered into an oil focused play in central Louisiana targeting the Austin Chalk formation through the execution of agreements to acquire interests in approximately 24,600 gross acres. The Company has invested approximately $15.0 million in acquisition, engineering and geological costs as of December 31, 2018 and issued 2.0 million shares of Predecessor common stock with respect to these interests.

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Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

12 Months Ended

Dec. 31, 2018

Reorganizations [Abstract]

Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

The Company's overall liquidity position and cash available for capital expenditures have been negatively impacted by weak natural gas prices, declining production and increasing cash interest expense on its outstanding indebtedness. In addition, beginning with the August 15, 2018 interest payment on the Company's 2021 PIK Notes (as defined below), the Company was required to pay interest on its 2021 PIK Notes at 10% in cash (instead of 1% in cash and 9% in payment in kind). The Company elected not to pay the cash interest payments that were due on August 15, 2018 under the Company's 2021 PIK Notes and 2021 Notes (as defined below) which totaled approximately $14.2 million (see Note 10 for additional information).

As a result of the forgoing, the Company engaged in discussions and negotiations with the lenders under the Multidraw Term Loan (as defined below), certain holders of the Company’s 2021 Notes and 2021 PIK Notes, and their legal and financial advisors regarding various alternatives with respect to the Company’s capital structure and financial position, including the significant amount of indebtedness, and the August 15, 2018 interest payments overdue on the Company’s 2021 Notes and 2021 PIK Notes.

As a result of the forgoing discussions and negotiations, on November 6, 2018 (the “Petition Date”), the Company, PetroQuest Energy, L.L.C. (“PQE”) and their direct and indirect wholly owned subsidiaries (collectively, the “Debtors”) filed voluntary petitions (collectively, the “Petition,” and the cases commenced thereby, the “Chapter 11 Cases”) seeking relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).

In connection with the Chapter 11 filing, on the Petition Date, the Debtors entered into a restructuring support agreement (the “Restructuring Support Agreement”) with (i) holders of 81.83% of the Company's 10% Second Lien Senior Secured Notes due 2021 (the “2021 Notes”) issued under that certain Indenture dated as of February 17, 2016, among the Company, the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee and collateral trustee thereunder, (ii) holders of 84.76% of the Company’s 10% Second Lien Senior Secured PIK Notes due 2021 (the “2021 PIK Notes”) issued under that certain Indenture dated as of September 27, 2016, among the Company, the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as indenture trustee and collateral trustee thereunder, and (iii) each of the lenders, or investment advisors or managers for the account of each of the lenders under the multidraw term loan agreement (the "Multidraw Term Loan Agreement"), by and among PQE, the Company, Wells Fargo Bank, National Association, as administrative agent, and lenders holding Term Loans (as defined therein) party thereto from time to time, pursuant to which such parties agreed to support the Plan (as defined below).

On January 31, 2019, the Court entered an order (the “Confirmation Order”) confirming the Debtors’ First Amended Chapter 11 Plan of Reorganization, as Immaterially Modified as of January 28, 2019 (as amended, modified or supplemented from time to time, the “Plan”) under Chapter 11 of the Bankruptcy Code. On February 8, 2019 (the “Effective Date”), the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases. On the Effective Date, TDC Energy, LLC, Pittrans, Inc. and Sea Harvester Energy Development, L.L.C. were dissolved. The remaining Debtors (collectively, the "Reorganized Debtors") continue in existence.

On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Company:

• Adopted an amended and restated certificate of incorporation and bylaws;

• Appointed four new members to the Successor’s board of directors to replace all of the directors of the Predecessor, other than the director also serving as Chief Executive Officer, who was re-appointed pursuant to the Plan;

• Cancelled all of the Predecessor’s common stock and 6.875% Series B Cumulative Convertible Perpetual Preferred Stock with the former holders thereof not receiving any consideration in respect of such stock;

• Issued to the former holders of the Predecessor’s 2021 Notes and 2021 PIK Notes, (collectively, the “Old Notes”), in exchange for the cancellation and discharge of the Old Notes:

◦ 8,900,000 shares of the Successor’s Class A Common Stock; and

◦ $80 million of the Successor’s 10% Senior Secured PIK Notes due 2024 (the “2024 PIK Notes”);

• Issued 300,000 shares of the Successor’s Class A Common Stock to certain former holders of the Old Notes for their commitment to backstop the Exit Facility (as defined below);

• Issued to the Class B Holder (as defined in the Successor’s amended and restated certificate of incorporation) one share of the Successor’s Class B Common Stock, which confers certain rights to elect directors and certain drag-along rights;

• Issued to the Class C Holder (as defined in the Successor’s amended and restated certificate of incorporation) one share of the Successor’s Class C Common Stock, which confers certain rights to elect directors and certain drag-along rights;

• Entered into a new $50 million senior secured Term Loan Agreement (the “Exit Facility”) upon the repayment and termination of the Predecessor’s Multidraw Term Loan Agreement;

• Entered into a registration rights agreement (the “Registration Rights Agreement”) with certain holders of the Successor’s Class A Common Stock and 2024 PIK Notes; and

• Adopted a new management incentive plan (the “2019 Long Term Incentive Plan”) for officers, directors and employees of the Successor and its subsidiaries, pursuant to which 1,344,000 shares of the Successor’s Class A Common Stock were reserved for issuance.

The foregoing is a summary of the substantive provisions of the Plan and related transactions and is not intended to be a complete description of, or a substitute for a full and complete reading of, the Plan and the other documents referred to above.

Effect of Filing on Creditors

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Petition automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement in the Bankruptcy Court. Although the filing of the Petition triggered defaults on the Debtors’ debt obligations, creditors were stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code.

Rejection of Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and satisfaction of certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtor's estate for damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with any of the Debtors, including where applicable a quantification of the Company’s obligations under any such executory contract or unexpired lease with the applicable Debtor, is qualified by any rights the Company has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto.

Debtor-In-Possession

During the pendency of the Chapter 11 Cases, the Debtors operated as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. In general, as debtors-in-possession under the Bankruptcy Code, the Debtors were authorized to continue to operate as an ongoing business, but were not permitted to engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court. Pursuant to motions filed with the Bankruptcy Court that were designed primarily to mitigate the impact of the Chapter 11 Cases on our operations, customers and employees, the Bankruptcy Court authorized the Debtors to conduct their business activities in the ordinary course, including, among other things and subject to the terms and conditions of such orders, authorizing the Debtors to: (i) pay employees' wages and related obligations; (ii) continue to operate their cash management system in a form substantially similar to pre-petition practice; (iii) continue to honor certain obligations related to our royalty obligations; and (iv) pay taxes in the ordinary course.

Reorganization Items

The Debtors have incurred costs associated with the reorganization, primarily legal and professional fees. In accordance with applicable guidance, costs associated with the bankruptcy proceedings have been recorded as reorganization items within the consolidated statement of operations for the year ended December 31, 2018. Reorganization items included $3.8 million related to post petition professional fees and $0.5 million related to adjustments to certain claims relating to the Chapter 11 Cases and to the carrying value of debt classified as liabilities subject to compromise.

Liabilities Subject to Compromise

The consolidated balance sheet as of December 31, 2018 includes amounts classified as liabilities subject to compromise, which represent liabilities which have been allowed as claims in the Chapter 11 Cases. These amounts represent the Debtors' current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process.

Liabilities subject to compromise at December 31, 2018 consisted of the following (in thousands):            

	December 31, 2018
10% Senior PIK Notes due 2021	$	275,046
10% Senior Notes due 2021	9,427
Accrued interest	20,624
Accounts payable to vendors	874
Other long-term liabilities	510
Other accrued liabilities	2,724
Preferred stock dividend payable	14,649
Liabilities subject to compromise	$	323,854

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Equity

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Equity

Equity

As discussed in “Note 2-Voluntary Reorganization under Chapter 11 of the Bankruptcy Code,” on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, all of the Predecessor’s common stock and 6.875% Series B Cumulative Convertible Perpetual Preferred Stock was canceled with the former holders thereof not receiving any consideration in respect thereof. Accordingly, the following discussion relates solely to the Predecessor’s common stock and 6.875% Series B Cumulative Convertible Perpetual Preferred Stock prior to such cancellation.

Common Stock

During December 2017, the Company issued 2.0 million shares of common stock in connection with the acquisition of Austin Chalk acreage (see Note 3). Additionally, during December 2017, the Company issued approximately 2.2 million shares of common stock related to the extinguishment of a portion of the outstanding 2021 Notes (see Note 10).

Convertible Preferred Stock

The Company had 1,495,000 shares of 6.875% Series B Cumulative Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) outstanding as of December 31, 2018 and 2017, all of which were canceled on the Effective Date pursuant to the Plan.    

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

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

In connection with an amendment to the Company's prior bank credit facility (which was replaced by the Old Loan Agreement (as defined below) in October 2016 and the Multidraw Term Loan Agreement in August 2018) prohibiting the Company from declaring or paying dividends on the Series B Preferred Stock, the Company suspended the quarterly cash dividend on the Series B Preferred Stock beginning with the dividend payment due on April 15, 2016. The Old Loan Agreement prohibited, and the Multidraw Term Loan Agreement also prohibited the Company from declaring and paying cash dividends on the Series B Preferred Stock. Under the terms of the Series B Preferred Stock, any unpaid dividends accumulated. As of December 31, 2018, the Company had deferred eleven quarterly dividend payments and had accrued a $14.6 million payable related to the eleven deferred quarterly dividends and the quarterly dividend that accrued through the bankruptcy filing date. The accrued dividend payable is included in liabilities subject to compromise on the consolidated balance sheet.

Mandatory conversion. The Company could, 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 gave the conversion notice equaled or exceeded 130% of the conversion price in effect on each such trading day.

Conversion rights. Each share of Series B Preferred Stock could be converted at any time, at the option of the holder, into 0.8608 shares of the Company’s common stock (which is based on an initial conversion price of approximately $58.08 per share of common stock, subject to further 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 elected 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 would have delivered upon conversion (if any) would be based upon a 20 trading day averaging period.

Upon any conversion, the holder would 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 was equal to $50 divided by the conversion price at the time. The conversion price was subject to adjustment upon the occurrence of certain events.

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Earnings Per Share

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Share

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, 2018	Loss(Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(13,919	)	25,581	$	(0.54	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(13,919	)	25,581	$	(0.54	)
For the Year Ended December 31, 2017	Loss(Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(11,776	)	21,330	$	(0.55	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(11,776	)	21,330	$	(0.55	)
For the Year Ended December 31, 2016	Loss(Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(96,245	)	18,354	$	(5.24	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(96,245	)	18,354	$	(5.24	)

An aggregate of 2.0 million, 1.6 million and 0.9 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock for the years ended December 31, 2018, 2017 and 2016, respectively, and common shares issuable upon the assumed conversion of the Series B Preferred Stock totaling 1.3 million shares for each of the periods presented were not included in the computation of diluted earnings per share for the years ended December 31, 2018, 2017 and 2016, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for the year.

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Share-Based Compensation

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

Share-Based Compensation

As discussed in “Note 2-Voluntary Reorganization under Chapter 11 of the Bankruptcy Code”, on the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, all of the Predecessor’s common stock (and any share-based compensation based on such common stock) was canceled with the former holders thereof not receiving any consideration in respect thereof. The Predecessor's share-based compensation plan was also terminated on the Effective Date. Accordingly, the following discussion relates solely to the Predecessor’s share-based compensation plan and share-based compensation issued and outstanding prior to such cancellation.    

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, 2018, 2017 and 2016 is as follows (in thousands):

	Year Ended December 31,
	2018			2017		2016
Stock options:
Incentive Stock Options (share settled)	$	407		$	820	$	206
Non-Qualified Stock Options (share settled)	94			387		164
Restricted stock (share settled)	465			197		1,073
Cash settled stock units	(241		)	245		244
Share-based compensation	$	725		$	1,649	$	1,687

During the years ended December 31, 2017 and 2016, the Company capitalized $103,000 and $106,000, respectively, 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, 2018. During the years ended December 31, 2018, 2017 and 2016, the Company recorded income tax benefits of approximately $101,000, $270,000 and $512,000, respectively, related to share-based compensation expense recognized during those periods. As a result of the adoption of ASU 2016-09 during the year ended December 31, 2017, the Company recognized an additional deferred tax asset of $4.7 million related to net operating loss carryforwards for excess tax benefits on share-based compensation that did not meet the criteria for recognition under previous guidance.

Share-Based compensation settled in shares

At December 31, 2018, the Company had $0.4 million of unrecognized compensation cost related to unvested restricted stock and stock options.

Stock Options

Stock options may be granted to employees and consultants and generally vest ratably over a three-year period. Stock options may also be granted to directors and generally vest one year or less from the date of grant to align with their term on the board. Stock options must be exercised within 10 years of the grant date. The exercise price of each option may not be less than 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 an 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.    

The following table outlines the assumptions used in computing the fair value of stock options granted during 2017 and 2016. No such grants were made during 2018.    

	2017	2016
Dividend yield	—%	—%
Expected volatility	80.44%	62.0%-79.99%
Risk-free rate	1.925%	1.255%-2.09%
Expected term	6 years	6 years
Stock options granted	219,130	1,168,754
Wgtd. avg. grant date fair value per share	$1.28	$1.96
Fair value of grants	$280,000	$2,293,000

     The following table details stock option activity during the year ended December 31, 2018:

	Number of Options		Wgtd. Avg. Exercise  Price		Wgtd. Avg. Remaining  Life	Aggregate Intrinsic  Value (000’s)
Outstanding at beginning of year	1,608,646		$	6.20
Granted	—		—
Expired/cancelled/forfeited	(121,823	)	4.98
Exercised	—		—
Outstanding at end of year	1,486,823		6.34		7.03	$	—
Options exercisable at end of year	1,047,590		$	7.78	6.64	$	—

The total fair value of stock options that vested during the years ended December 31, 2018, 2017 and 2016 was $1.2 million, $1.6 million and $0.4 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, 2018:

Range of	Options	Wgtd. Avg.	Wgtd. Avg.	Options	Wgtd. Avg.
Exercise	Outstanding	Remaining	Exercise	Exercisable	Exercise
Price	12/31/2018	Contractual Life	Price	12/31/2018	Price
$0.00-$2.37	250,477	8.43	$1.99	105,780	$2.07
$3.17-$4.36	1,013,663	7.68	$3.37	719,127	$3.36
$16.72-$19.52	68,190	4.42	$17.11	68,190	$17.11
$20.40-$30.32	154,493	1.73	$28.15	154,493	$28.15
	1,486,823			1,047,590	$7.78

Restricted Stock

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. Restricted stock granted to employees generally vests ratably over a three-year period. Restricted stock granted to directors vests one year or less 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.

The following table details restricted stock activity during the year ended December 31, 2018:

	Number of Shares		Wgtd. Avg. Fair Value  per Share
Outstanding at beginning of year	487,502		$1.87
Cancelled/forfeited	(34,946	)	$1.85
Lapse of restrictions	(37,500	)	$2.15
Outstanding at December 31, 2018	415,056		$1.85

The weighted average grant date fair value of restricted stock granted during the year ended December 31, 2017 was $1.87 per share. No restricted stock was granted in 2018 and 2016. The total fair value of restricted stock that vested during the years ended December 31, 2018, 2017 and 2016 was $0.1 million, $1.3 million and $2.4 million, respectively.

Share-Based compensation settled in cash

Restricted Stock Units

The Company may grant restricted stock units ("RSUs") to employees that vest ratably 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 2018 and 2017, the Company paid $24,000 and $59,000, respectively, to settle 323,374 and 31,703 RSUs, respectively, that vested during the period.

Market Based Restricted Stock Units

The Company granted 60,767 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 2014 MRSUs vested 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. In November 2017, the Company granted an additional 270,269 MRSUs. The performance period ended on December 31, 2018 for these grants and executive officers earned none of the MRSUs. 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 stock prices of the Company and its peer group, a risk-free interest rate, and an estimated volatility for the Company and its peer group. As of December 31, 2018, the Company had no liability for RSUs outstanding and as of December 31, 2017, the Company had a liability for RSUs and MRSUs outstanding in the amount of $0.3 million, based upon the closing stock price at December 31, 2018 and December 31, 2017, respectively.

The following table details MRSU and RSU activity during the year ended December 31, 2018:

	MRSU		RSU		Total
Outstanding at beginning of year	277,733		889,587		1,167,320
Granted	—		—		—
Expired/Cancelled/Forfeited	(270,269	)	(78,808	)	(349,077	)
Vested/Paid	(7,464	)	(323,374	)	(330,838	)
Outstanding at December 31, 2018	—		487,405		487,405

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Asset Retirement Obligation

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

Asset Retirement Obligation

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 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 summarizes the changes to the Company’s asset retirement obligation (in thousands):

	Year Ended December 31,
	2018			2017
Asset retirement obligation, beginning of period	$	31,310		$	36,610
Liabilities incurred	7			574
Liabilities settled	(863		)	(3,364		)
Accretion expense	322			2,252
Revisions in estimated cash flows	(62		)	(4,514		)
Divestiture of oil and gas properties	(28,234		)	(248		)
Asset retirement obligation, end of period	2,480			31,310
Less: current portion of asset retirement obligation	(183		)	(687		)
Long-term asset retirement obligation	$	2,297		$	30,623

Divestitures of oil and gas properties during 2018 included $28.2 million as a result of the sale of the Company's Gulf of Mexico assets in January 2018. The liabilities incurred, revisions in estimated cash flows and divestitures represent non-cash investing activities for purposes of the statement of cash flows.

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Derivative Instruments

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

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, 2017, all of the Company's outstanding derivative instruments were designated as cash flow hedges. The Company had no outstanding derivative contracts as of December 31, 2018.

Oil and gas sales include additions related to the settlement of gas hedges of $0.8 million, $1.5 million and $1.8 million, for the years ended December 31, 2018, 2017 and 2016, respectively. Oil and gas sales include reductions of $1.4 million related to the settlement of oil hedges for the year ended December 31, 2018. There were no settlements of Ngls for any period presented or oil hedges for the years ended December 31, 2017 and 2016. On June 14, 2018, the Company's hedging counterparty, Koch Supply & Trading LP, terminated the only outstanding hedge contract resulting in a settlement of $0.5 million. The settlement at the termination date remained in accumulated other comprehensive loss and was reclassified to earnings as the hedged volumes were produced over the original term of the contract.

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, 2017:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
December 31, 2017	Derivative asset	$	1,174
December 31, 2017	Derivative liability	$	(731	)

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for years ended December 31, 2018, 2017 and 2016:

Instrument	Amount of Gain (Loss) Recognized in Other Comprehensive Income			Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into Income
Commodity Derivatives at December 31, 2018	$	(990	)	Oil and gas sales	$	(622	)
Commodity Derivatives at December 31, 2017	$	6,654		Oil and gas sales	$	1,461
Commodity Derivatives at December 31, 2016	$	(4,447	)	Oil and gas sales	$	1,811

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Fair Value Measurements

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

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, 2017 were in the form of swaps based on NYMEX pricing for oil and natural gas. The fair value of these derivatives was 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 designated its commodity derivatives as Level 2 in the fair value hierarchy. The Company had no outstanding derivative contracts at December 31, 2018.

The following table summarizes the Company’s assets (liabilities) that are subject to fair value measurement on a recurring basis as of December 31, 2017 (in thousands):

	Fair Value Measurements Using
Instrument	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity Derivatives:
At December 31, 2017	$	—	$	443	$	—

The fair value of the Company's cash and cash equivalents approximated book value at December 31, 2018 and 2017. The fair value of the Multidraw Term Loan Agreement approximated face value as of December 31, 2018 and 2017. The fair value of the Company's 2021 Notes and 2021 PIK Notes was determined based upon market quotes provided by an independent broker, which represents a Level 2 input. The fair value of the 2021 Notes was $2.8 million and $7.3 million and the fair value of the 2021 PIK Notes was $82.5 million and $198.7 million as of December 31, 2018 and 2017, respectively.

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Long-Term Debt

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Predecessor Long-Term Debt

On August 19, 2010, the Company issued $150 million in principal amount of its 10% Senior Notes due 2017. On July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (collectively, the "2017 Notes").

On February 17, 2016, the Company closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. In satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the then outstanding aggregate principal amount of 2017 Notes, the Company (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of its new 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately 1.1 million shares of Predecessor common stock. Following the completion of the February Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.

On September 27, 2016, the Company closed private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes and 2021 Notes. In satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the then outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the then outstanding aggregate principal amount of 2021 Notes, the Company issued (i) $243.5 million in aggregate principal amount of its new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately 3.5 million shares of Predecessor common stock. The Company also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including, September 27, 2016. Following the consummation of the September Exchange, there were $22.7 million in aggregate principal amount of the 2017 Notes outstanding and $14.2 million in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes.

On March 31, 2017, the Company redeemed the remaining outstanding 2017 Notes at a redemption price of $22.8 million. The redemption was funded by cash on hand and amounts borrowed under the Old Loan Agreement described below. On December 28, 2017, the Company issued 2.2 million shares of Predecessor common stock to extinguish approximately $4.8 million of outstanding principal amount of 2021 Notes.

The 2021 PIK Notes accrued interest at a rate of 10% per annum on the principal amount and interest was payable semi-annually in arrears on February 15 and August 15 of each year. The Company was permitted, at its option, for the first three interest payment dates of the 2021 PIK Notes, to instead pay interest at (i) the annual rate of 1% in cash plus (ii) the annual rate of 9% PIK (the "PIK Interest") payable by increasing the principal amount outstanding of the 2021 PIK Notes or by issuing additional 2021 PIK Notes in certificated form. The Company exercised this PIK option in connection with the interest payments due on February 15, 2017, August 15, 2017 and February 15, 2018.

The 2021 Notes accrued interest at a rate of 10% per annum on the principal amount and interest was payable semi-annually in arrears on February 15 and August 15 of each year.

The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to ASC Topic 470-60 "Troubled Debt Restructurings by Debtors." The Company determined that the future undiscounted cash flows from the 2021 PIK Notes issued in the September Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes and the 2021 Notes tendered in the September Exchange. Accordingly, no gain or loss on extinguishment of debt was recognized in connection with the September Exchange. The net shortfall of the remaining carrying value of the 2017 Notes and 2021 Notes tendered as compared to the principal amount of the 2021 PIK Notes issued in the September Exchange of $0.6 million was reflected as part of the carrying value of the 2021 PIK Notes. Such shortfall was being amortized under the effective interest method over the term of the 2021 PIK Notes.

The Company previously determined that the future undiscounted cash flows from the 2021 Notes issued in the February Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the February Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the February Exchange. The excess of the remaining carrying value of the 2017 Notes tendered over the principal amount of the 2021 Notes issued in the February Exchange of $13.9 million was reflected as part of the carrying value of the 2021 Notes. The amount of the excess carrying value attributable to the 2021 Notes tendered in the September Exchange was then reflected as part of the carrying value of the 2021 PIK Notes. The excess carrying value attributable to the remaining 2021 Notes was being amortized under the effective interest method over the term of the 2021 Notes.

On October 17, 2016, the Company entered into a multidraw term loan agreement (the "Old Loan Agreement") with Franklin Custodian Funds - Franklin Income Fund, as a lender, and Wells Fargo Bank, National Association, as administrative agent (the "Agent"), replacing the prior credit agreement with JPMorgan Chase Bank, N.A. Effective August 14, 2018, the Company and certain of its subsidiaries entered into a Forbearance Agreement (the "Forbearance Agreement") with the Agent for the lenders with respect to the Old Loan Agreement. Pursuant to the Forbearance Agreement, the Agent and the lenders under the Old Loan Agreement agreed to forbear from taking any action with respect to certain specified events of default occurring under the Old Loan Agreement as a result of non-payment by the Company of interest with respect to the 2021 PIK Notes and 2021 Notes when due and payable on August 15, 2018 under the indentures governing those notes. On August 31, 2018, the Company and PetroQuest Energy, L.L.C. entered into a new Multidraw Term Loan Agreement (the "Multidraw Term Loan Agreement"), which replaced the Old Loan Agreement with the lenders party thereto from time to time (the "Lenders") and the Agent. The Multidraw Term Loan Agreement provided a multi-advance term loan facility in the principal amount of up to $50.0 million. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) were permitted to be used to repay existing debt, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes. On August 31, 2018, the Company borrowed $50.0 million under the Term Loans, and repaid $32.5 million of outstanding borrowings under the Old Loan Agreement, plus accrued interest and fees, and retained the balance of the borrowings for general corporate purposes. As of December 31, 2018, the Company had no borrowing availability under the Multidraw Term Loan Agreement.

Effective September 14, 2018, the Company and certain of its subsidiaries entered into a Forbearance Agreement (the "Loan Forbearance Agreement") with the Agent for the lenders with respect to the Multidraw Term Loan Agreement. Pursuant to the Loan Forbearance Agreement, the Agent and Lenders agreed to forbear from taking any action with respect to certain anticipated events of default occurring under the Multidraw Term Loan Agreement as a result of the non-payment of interest with respect to the 2021 Notes and 2021 PIK Notes when due and payable on August 15, 2018, and such non-payment continuing for a period of 30 days under the indentures governing the notes. The Loan Forbearance Agreement was effective from September 14, 2018 until the earlier of (i) 11:59 p.m. Eastern time on September 28, 2018 or (ii) the occurrence of any specified forbearance default, which includes, among other things, any event of default under the Multidraw Term Loan Agreement other than the anticipated events of default or a breach by the Company or certain of its subsidiaries of the Loan Forbearance Agreement. On September 28, 2018, October 5, 2018, October 19, 2018 and October 31, 2018, the Company and certain of its subsidiaries, the Agent and the Lenders entered into first, second, third and fourth amendments to the Loan Forbearance Agreement that extended the September 28, 2018 deadline to 11:59 p.m. Eastern time on each of October 5, 2018, October 19, 2018, October 31, 2018 and November 6, 2018, respectively. The Loan Forbearance Agreement terminated on the commencement of the Chapter 11 Cases described in Note 2.

Effective September 14, 2018, the Company and certain of its subsidiaries entered into (i) a Forbearance Agreement (the "2021 Notes Forbearance Agreement") with certain holders (the "2021 Notes Supporting Holders") of approximately $7.3 million in aggregate principal amount (representing approximately 77.9% of the outstanding principal amount) of the 2021 Notes, and (ii) a Forbearance Agreement (the "2021 PIK Notes Forbearance Agreement" and together with the 2021 Notes Forbearance Agreement, the "Notes Forbearance Agreements") with certain holders (the "2021 PIK Notes Supporting Holders" and together with the 2021 Notes Supporting Holders, the "Supporting Holders") of approximately $194.6 million in aggregate principal amount (representing approximately 70.7% of the outstanding principal amount) of the 2021 PIK Notes.

Pursuant to the Notes Forbearance Agreements, the Supporting Holders agreed to forbear from exercising their rights and remedies under their respective indentures governing the 2021 Notes and the 2021 PIK Notes or the related security documents with respect to certain anticipated events of default occurring under the indentures as a result of the non-payment by the Company of interest with respect to the 2021 Notes and the 2021 PIK Notes when due and payable on August 15, 2018 and such non-payment continuing for a period of 30 days, until the earlier of (i) 11:59 p.m. Eastern time on September 28, 2018 and (ii) the date the Notes Forbearance Agreements otherwise terminate in accordance with the terms therein (the "Forbearance Period"). Pursuant to the Notes Forbearance Agreements, the Supporting Holders agreed to not deliver any notice or instruction in respect of the exercise of any of the rights and remedies otherwise available under the indentures or the related security documents with respect to such anticipated events of default. The Supporting Holders also agreed to not transfer any ownership in the 2021 Notes and the 2021 PIK Notes held by any of the Supporting Holders during the Forbearance Period other than to potential transferees currently parties to, or who agree in writing to be bound by, the Notes Forbearance Agreements. On September 28,2018, October 5, 2018, October 19, 2018 and October 31, 2018, the Company and certain of its subsidiaries, and the Supporting Holders entered into first, second, third and fourth amendments to the Notes Forbearance Agreements that extended the September 28, 2018 deadline to 11:59 p.m. Eastern time on each of October 5, 2018, October 19, 2018, October 31, 2018 and November 6, 2018, respectively. The Notes Forbearance Agreements terminated on the commencement of the Chapter 11 Cases described in Note 2.

The face value of the 2021 Notes and the 2021 PIK Notes, including accrued PIK interest, is classified as liabilities subject to compromise as of December 31, 2018. The Term Loans are reflected net of $0.3 million and $2.0 million of related unamortized deferred financing costs as of December 31, 2018 and 2017, respectively. The adjustments to write off the remaining unamortized deferred financing costs and carrying value adjustments related to the February Exchange and September Exchange are included in reorganization items in the consolidated statement of operations.

Successor Long-Term Debt

On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Company entered into the Term Loan Agreement (the “Exit Facility”) with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent. The Exit Facility provides for a $50 million term loan facility.

The proceeds of the Exit Facility were used to repay in full the loans and other obligations under the Multidraw Term Loan Agreement. The maturity date of the Exit Facility is November 8, 2023. The interest rate per annum is equal to (i) in the case of LIBOR Loans (as defined in the Exit Facility), 7.5% per annum and (ii) in the case of Base Rate Loans (as defined in the Exit Facility), 6.5% per annum. The Exit Facility is secured by a first priority lien on substantially all of the Company's assets.

The Company is subject to a restrictive covenant under the Exit Facility, consisting of maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of its oil and gas properties, before any state, federal, foreign or other income taxes, attributable to total proved reserves, using strip prices then in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the aggregate outstanding principal amount of the term loans to be less than 1.50 to 1.00 as measured on the last day of each calendar. If the Company fails to maintain the ratio, it may either (i) prepay the outstanding term loans such that after giving effect to such prepayment, the financial covenant is met or (ii) be in default under the Exit Facility, in which case the term loans and all other amounts owed pursuant to the Exit Facility would become immediately due and payable.

The Exit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, entering into mergers, consolidations and sales of assets, and transactions with affiliates and other customary covenants.

The Exit Facility contains customary events of default and remedies for credit facilities of this nature. If the Company does not comply with the financial and other covenants in the Exit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Exit Facility. An event of default under the Exit Facility, if not cured or waived, could result in an event of default under the 2024 PIK Notes (as defined below).

On the Effective Date and pursuant to the terms of the Plan and the Confirmation Order, the Company entered into an indenture (the “Indenture”) with Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral agent, and issued $80 million of its new 10% Senior Secured PIK Notes due 2024 (the “2024 PIK Notes”) pursuant thereto.

Interest on the 2024 PIK Notes accrues at a rate of 10% per annum payable semi-annually in kind (“PIK Interest”) on February 15 and August 15 of each year, beginning on August 15, 2019. At the election of the Board of Directors, so long as the Company has provided notice to the holders of the 2024 PIK Notes and the Trustee of such election at least 30 days prior to any applicable interest payment date, interest on the 2024 PIK Notes for any interest period may instead be payable at the annual rate (i) solely in cash (the “Cash Interest”) or (ii) partially as Cash Interest and partially as PIK Interest. The maturity date of the 2024 Notes is February 15, 2024. The 2024 PIK Notes are secured on a second priority lien basis by the equity of the Company's subsidiary PetroQuest Energy, LLC that also secures the Exit Facility. Pursuant to the terms of an intercreditor agreement, the security interest in those assets that secure the 2024 PIK Notes and the related guarantee will be contractually subordinated to liens thereon that secure the Exit Facility and certain other permitted obligations as set forth in the Indenture. Consequently, the 2024 PIK Notes and the related guarantee will be effectively subordinated to the Exit Facility and such other permitted obligations to the extent of the value of such assets.

The Company may, at its option, on any one or more occasions redeem all or a portion of the 2024 PIK Notes issued under the Indenture at the redemption prices set forth below (expressed in percentages of principal amount on the redemption date), plus accrued and unpaid Cash Interest together with an amount of cash equal to all accrued and unpaid PIK Interest on the 2024 PIK Notes to be redeemed to, but not including, the redemption date (subject to the right of holders of the 2024 PIK Notes of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the periods set forth below:

PeriodRedemption Price

February 8, 2019 to February 7, 2020        102.000%

February 8, 2020 to February 7, 2021        101.000%

February 8, 2021 and thereafter            100.000%

Upon the occurrence of certain change of control events, any holder of the 2024 PIK Notes will have the right to cause the Company to repurchase all or any part of such holder’s 2024 PIK Notes at a repurchase price payable in cash equal to 101% of the principal amount of the 2024 PIK Notes to be repurchased (including any PIK Notes (as defined in the Indenture) or any increase in principal amount of the 2024 PIK Notes in connection with PIK Interest, plus accrued interest to the date of repurchase (subject to the right of holders of record on the relevant record date to receive interest due on the related interest payment date).

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Related Party Transactions

12 Months Ended

Dec. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

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 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.

During 2018, 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 $0 and $20,000, respectively. During 2017, 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 $(107,000) and $41,000, respectively. During 2016, 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 $(15,000) and $25,000, respectively. 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, 2018, the Company’s joint interest billing receivable included no amounts due from the related parties discussed above or their affiliates, attributable to their share of costs.

In December 2017, the Company sold certain saltwater disposal assets in East Texas to a third party purchaser. In connection with the sale, the Company also entered into a volumetric commitment to deliver saltwater volumes to the purchaser of the saltwater disposal assets over a six year period. One of the minority owners of the purchaser is the son of Dr. Charles Mitchell, II, a member of our Predecessor's board of directors. The transactions were approved by the Predecessor's Audit Committee.

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Ceiling Test Write-down

12 Months Ended

Dec. 31, 2018

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Ceiling Test Write-down

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, 2016, 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 $2.51 per Mcf of natural gas, $40.85 per barrel of oil and $1.82 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 $40.3 million during the year ended December 31, 2016. The Company’s cash flow hedges in place decreased these ceiling test write-downs by approximately $8.0 million for the year ended December 31, 2016. The Company did not recognize a ceiling test write-down during the years ended December 31, 2018 and 2017.

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Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Other Comprehensive Income (Loss)

Other Comprehensive Income (Loss)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2016 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2015	$	947		$	—		$	947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	(4,447		)	—			(4,447		)
Income tax effect	1,654			(1,654		)	—
Net of tax	(2,793		)	(1,654		)	(4,447		)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(1,811		)	—			(1,811		)
Income tax effect	674			(113		)	561
Net of tax	(1,137		)	(113		)	(1,250		)
Net other comprehensive loss	(3,930		)	(1,767		)	(5,697		)
Balance as of December 31, 2016	$	(2,983	)	$	(1,767	)	$	(4,750	)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2017 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2016	$	(2,983	)	$	(1,767	)	$	(4,750	)
Other comprehensive income before reclassifications:				—
Change in fair value of derivatives	6,654			—			6,654
Income tax effect	(2,475		)	1,767			(708		)
Net of tax	4,179			1,767			5,946
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(1,461		)	—			(1,461		)
Income tax effect	543			—			543
Net of tax	(918		)	—			(918		)
Net other comprehensive loss	$	3,261		$	1,767		$	5,028
Balance as of December 31, 2017	$	278		$	—		$	278

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2018 (in thousands):        

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2017	$	278
Other comprehensive income before reclassifications:
Change in fair value of derivatives	(990		)
Income tax effect	238
Net of tax	(752		)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	622
Income tax effect	(148		)
Net of tax	474
Net other comprehensive loss	(278		)
Balance as of December 31, 2018	$	—

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Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company typically provides for income taxes at the statutory federal income tax rate 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 three-year cumulative 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, of which there were none as of December 31, 2018. The Company had a valuation allowance of $118.7 million as of December 31, 2018 and $115.9 million as of December 31, 2017.

The Tax Cuts and Jobs Act (the “Act”) was enacted on December 22, 2017. The Act, among other things, reduces the U.S. federal corporate tax rate from 35% to 21%, eliminates the corporate alternative minimum tax and changes how existing alternative minimum tax credits are realized, creates a new limitation on deductible interest expense and changes the rules related to uses and limitations of net operating loss carryforwards generated in tax years beginning after December 31, 2017. The Company made a reasonable estimate of the effects on its existing deferred tax balances and recognized a provisional amount of $64.9 million as of December 31, 2017 to remeasure deferred tax assets and liabilities based on the rate at which they are expected to reverse in the future, which is generally 21%. This amount was included as a component of income tax expense (benefit) from continuing operations and was fully offset by the related adjustment to the Company’s valuation allowance. The Company finalized its accounting for the Act in connection with the filing of its 2017 federal tax return and determined no adjustment was necessary to the previously recognized provisional amount.

As a result of the adoption of ASU 2016-09 during the year ended December 31, 2017, the Company recognized an additional deferred tax asset of $4.7 million related to net operating loss carryforwards for excess tax benefits on share-based compensation that did not meet the criteria for recognition under previous guidance. This additional deferred tax asset was fully offset by the related adjustment to the Company's valuation allowance. The cumulative effect adjustment to record the previously unrecognized excess tax benefits and the related adjustment to the valuation allowance, were recorded in retained earnings on the date of adoption.

An analysis of the Company’s deferred tax assets and liabilities follows (amounts in thousands):

	December 31,
	2018			2017
Net operating loss carryforwards	$	86,046		$	78,541
Percentage depletion carryforward	6,011			5,701
Interest expense carryforward	10,540			—
Contributions carryforward and other	194			192
Temporary differences:
Oil and gas properties	3,673			8,279
Asset retirement obligation	602			7,602
Derivatives	—			(107		)
Share-based compensation	1,403			1,269
Original issue discount on debt exchanges	9,815			14,429
Other	432			—
Valuation allowance	(118,716		)	(115,906		)
Deferred tax asset (liability)	$	—		$	—

At December 31, 2018, the Company had approximately $355.4 million of federal net operating loss carryforwards. If not utilized, approximately $6.9 million of such carryforwards would expire in 2025, $328.2 million would expire by the year 2037 and $20.3 million does not expire and is subject to a limitation of 80% of taxable income. The Company also had approximately $180.7 million of Louisiana state net operating loss carryforwards as of December 31, 2018. If not utilized, approximately $0.3 million of such carryforwards would expire during 2019 and the remainder would expire by the year 2038. The Company has available for tax reporting purposes $28.2 million in statutory depletion deductions that may be carried forward indefinitely. The Company had approximately $43.9 million of carryforwards related to the limitation on deductible interest expense. The interest expense carryforward does not expire and is subject to a limitation of 30% of adjusted taxable income.

Income tax expense (benefit) for each of the years ended December 31, 2018, 2017 and 2016 was different than the amount computed using the federal statutory rate (21%) for the following reasons (amounts in thousands):

	For the Year Ended December 31,
	2018			2017			2016
Amount computed using the statutory rate	$	(1,973	)	$	(2,655	)	$	(31,623	)
Increase (reduction) in taxes resulting from:
Impact of rate change on deferred tax	—			64,915			—
State & local taxes	(1,731		)	(368		)	(2,000		)
Percentage depletion carryforward	(256		)	(66		)	(163		)
Non-deductible stock option expense (1)	98			305			77
Share-based compensation (2)	—			64			707
Restructuring costs	1,528			—			—
Other	93			(21		)	1,415
Change in valuation allowance	2,393			(63,123		)	32,130
Income tax expense (benefit)	$	152		$	(949	)	$	543

(1) Relates to compensation expense related to 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.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

The Company 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. Although we cannot predict the outcome of these proceedings with certainty, management believes that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material adverse effect on the Company's business or financial position.

The commencement of the Chapter 11 Cases automatically stayed litigation and claims that were or could have been brought prior to November 6, 2018. The claims related to two class action lawsuits filed in October 2016 will be treated as general unsecured claims with a maximum amount that may be distributed to the holders of such claims not to exceed $400,000 under the Plan.

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, 2018 under these operating leases are as follows (in thousands):

2019	$	1,240
2020	1,173
2021	445
2022	431
2023	392
Thereafter	—
	$	3,681

Total rent expense under operating leases was approximately $1.5 million for each of 2018, 2017 and 2016, respectively.

Subsequent to December 31, 2018 and as part of the Chapter 11 Cases, the Company entered into a lease amendment with regard to its office space in The Woodlands, Texas, which reduced the above noted lease commitments by $1.3 million thru 2022.

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Supplementary Information on Oil and Gas Operations—Unaudited

12 Months Ended

Dec. 31, 2018

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplementary Information of Oil and Gas Operations—Unaudited

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)

	For the Year-Ended December 31,
	2018			2017			2016
Acquisition costs:
Proved	$	241		$	1,330		$	3,346
Unproved (1)	6,190			12,762			2,197
Divestiture of proved leasehold	(2,604		)	(4,795		)	(7,000		)
Exploration costs:
Proved	(51		)	9,466			715
Unproved	233			(287		)	603
Development costs (2)	(18,928		)	32,622			1,522
Capitalized general and administrative and interest costs	8,070			8,269			7,558
Total costs incurred	$	(6,849	)	$	59,367		$	8,941

	For the Year-Ended December 31,
	2018			2017			2016
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	$	(1,285,660	)	$	(1,243,286	)	$	(1,157,455	)
Provision for DD&A	(22,410		)	(31,667		)	(27,962		)
Ceiling test writedown	—			—			(40,304		)
Sale of proved properties and other (3)	6,478			(10,707		)	(17,565		)
Balance, end of year	$	(1,301,592	)	$	(1,285,660	)	$	(1,243,286	)
DD&A per Mcfe	$	1.05		$	1.15		$	1.19

(1) During 2017, the Company acquired approximately 24,600 gross acres for approximately $9.3 million in cash and 2.0 million shares of common stock. In total for 2017 and 2018, the Company has invested approximately $15.0 million in leasing costs and geological and engineering data.

(2) During 2018, the Company sold its Gulf of Mexico properties and removed approximately $28.2 million of future discounted asset retirement obligations, which was recorded as a reduction in the capitalized costs of oil and gas properties.

(3) During 2018, the Company sold its Gulf of Mexico properties, receiving no cash consideration and funding amounts related to the future abandonment costs for the properties and purchase price adjustments. During 2017, the Company sold its East Lake Verret assets for net proceeds of approximately $2.2 million and its East Texas saltwater disposal assets for net proceeds of $8.5 million. During 2016, the Company sold its remaining Oklahoma producing assets for net proceeds of $17.6 million.

At December 31, 2018 and 2017, unevaluated oil and gas properties totaled $23.5 million and $21.9 million, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2018 included $0.9 million of costs related to wells in progress at year-end. At December 31, 2017, unevaluated costs included $0.7 million related to two facilities in progress at year-end, which were transferred to evaluated oil and gas properties during 2018. The Company capitalized $1.8 million, $1.6 million and $0.9 million of interest during 2018, 2017 and 2016, respectively. Of the total unevaluated oil and gas property costs of $23.5 million at December 31, 2018, $7.4 million, or 32%, was incurred in 2018, $13.9 million, or 59%, was incurred in 2017 and $2.2 million, or 9%, was incurred in prior years. In connection with the sale of the Company's Gulf of Mexico assets, approximately $5.5 million, or 25% of the total unevaluated balance at December 31, 2017, was transferred to evaluated oil and gas properties in 2018. Of the remaining unevaluated balance at December 31, 2018, the Company expects the majority of the costs will be evaluated within the next three years, including $2.7 million expected to be evaluated during 2019.

Oil and Gas Reserve Information

The Company’s net proved oil and gas reserves at December 31, 2018 have been estimated by independent petroleum engineers in accordance with guidelines established by the SEC using a historical 12-month, first of 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.

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:

	Oil in MBbls		NGL in MMcfe		Natural Gas in MMcf		Total Reserves in MMcfe
Proved reserves as of December 31, 2015	1,806		34,826		132,344		178,004
Revisions of previous estimates	247		(4,380	)	(11,854	)	(14,748	)
Extensions, discoveries and other additions	—		—		1,485		1,485
Sale of reserves in place	(154	)	—		(24,834	)	(25,759	)
Production	(502	)	(3,871	)	(16,617	)	(23,501	)
Proved reserves as of December 31, 2016	1,397		26,575		80,524		115,481
Revisions of previous estimates	308		(7,269	)	381		(5,040	)
Extensions, discoveries and other additions	777		4,565		64,704		73,931
Purchase of producing properties	48		—		473		761
Sale of reserves in place	(90	)	—		(1,033	)	(1,573	)
Production	(592	)	(4,450	)	(19,611	)	(27,613	)
Proved reserves as of December 31, 2017	1,848		19,421		125,438		155,947
Revisions of previous estimates	130		(1,469	)	2,737		2,044
Extensions, discoveries and other additions	41		2,929		7,947		11,121
Sale of reserves in place	(507	)	(486	)	(13,945	)	(17,472	)
Production	(326	)	(3,373	)	(16,013	)	(21,335	)
Proved reserves as of December 31, 2018	1,186		17,022		106,164		130,305
Proved developed reserves
As of December 31, 2016	1,212		13,073		47,349		67,694
As of December 31, 2017	1,078		12,564		57,409		76,441
As of December 31, 2018	567		10,220		47,516		61,143
Proved undeveloped reserves
As of December 31, 2016	185		13,502		33,175		47,787
As of December 31, 2017	770		6,857		68,029		79,506
As of December 31, 2018	619		6,802		58,648		69,162

Year Ended December 31, 2018

During 2018, the Company’s estimated proved reserves decreased by 16%. The decrease in reserves was the result of 10.1 Bcfe removed as a result of the sale of our Gulf of Mexico assets in January 2018 and 7.3 Bcfe removed due to the selldown of certain of our PUDs in East Texas. Partially offsetting these decreases was an increase of 11.1 Bcfe of PUD reserves from third party drilling as well as the Company's leasing efforts in East Texas. Overall, the Company had a 100% drilling success rate on two wells completed during 2018.

Year Ended December 31, 2017

During 2017, the Company’s estimated proved reserves increased by 35%. The increase in reserves was the result of 73.9 Bcfe added due to the Company's drilling program in East Texas where it drilled eight gross wells during 2017. In response to low ethane prices, during 2017 the Company elected to bypass ethane processing on a portion of its East Texas production. As a result, the Company reduced its estimated proved ngl reserves to reflect the assumption that ethane would continue to not be recovered as natural gas liquids. Overall, the Company had a 100% drilling success rate during 2017.

Year Ended December 31, 2016

During 2016, the Company's estimated proved reserves decreased by 35% primarily due to the divestiture of the Company's remaining Oklahoma assets and significant reductions in capital spending during 2016. Extensions, discoveries and other additions of 1.5 Bcfe were primarily due to the successful completion of the Company's final Oklahoma wells. Revisions of previous estimates included the reclassification of certain PUD reserves to probable reserves as a result of the Company's assessment of the timing of development. Overall, the Company had a 100% drilling success rate during 2016 on 5 gross wells drilled.

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

	December 31,
	2018			2017			2016
Future cash flows	$	482,766		$	539,244		$	299,035
Future production costs	(171,999		)	(184,171		)	(117,283		)
Future development costs	(73,258		)	(128,447		)	(83,720		)
Future income taxes	—			—			—
Future net cash flows	237,509			226,626			98,032
10% annual discount	(113,484		)	(99,329		)	(30,763		)
Standardized measure of discounted future net cash flows	$	124,025		$	127,297		$	67,269

Changes in Standardized Measure

	Year Ended December 31,
	2018			2017			2016
Standardized measure at beginning of year	$	127,297		$	67,269		$	127,685
Sales and transfers of oil and gas produced, net of production costs	(64,148		)	(70,362		)	(35,993		)
Changes in price, net of future production costs	18,542			53,516			(30,427		)
Extensions and discoveries, net of future production and development costs	2,983			50,977			864
Changes in estimated future development costs, net of development costs incurred during this period	16,241			17,144			26,356
Revisions of quantity estimates	2,755			(7,482		)	(14,889		)
Accretion of discount	12,730			6,727			12,769
Purchase of reserves in place	—			549			—
Sale of reserves in place	1,614			(1,305		)	(16,701		)
Changes in production rates (timing) and other	6,011			10,264			(2,395		)
Net increase (decrease) in standardized measure	(3,272		)	60,028			(60,416		)
Standardized measure at end of year	$	124,025		$	127,297		$	67,269

The historical twelve-month, first day of the month, average prices of oil, gas and natural gas liquids used in determining standardized measure were:

	2018	2017	2016
Oil, $/Bbl	$68.71	$52.49	$40.85
Ngls, $/Mcfe	4.08	3.23	2.40
Natural Gas, $/Mcf	3.13	3.03	1.82

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Summarized Quarterly Financial Information - Unaudited

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Information - Unaudited

Summarized Quarterly Financial Information - Unaudited

Summarized quarterly financial information is as follows (amounts in thousands except per share data):

	Quarter Ended
	March 31			June 30			September 30			December 31
2018
Revenues	$	24,917		$	21,507		$	20,886		$	19,789
Income (loss) from operations	(821		)	(1,326		)	(3,657		)	701
Loss available to common stockholders	(2,212		)	(2,611		)	(4,979		)	$	(4,117	)
Loss per share:
Basic	$	(0.09	)	$	(0.10	)	$	(0.19	)	$	(0.16	)
Diluted	$	(0.09	)	$	(0.10	)	$	(0.19	)	$	(0.16	)
2017
Revenues	$	20,772		$	24,251		$	28,184		$	35,080
Income (loss) from operations	(3,633		)	(2,289		)	(1,885		)	221
Loss available to common stockholders	(4,918		)	(3,385		)	(3,085		)	(389		)
Loss per share:
Basic	$	(0.23	)	$	(0.16	)	$	(0.15	)	$	(0.02	)
Diluted	$	(0.23	)	$	(0.16	)	$	(0.15	)	$	(0.02	)

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Organization and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Principles of Consolidation

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.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States ("US GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserves and future net cash flows from estimated proved reserves are based on geological and engineering data and depend upon a number of variable factors and assumptions. Changes in estimated proved oil and gas reserves used in the calculation of depreciation, depletion and amortization of oil and gas properties or the present value of the estimated future net cash flows from estimated proved reserves used in the ceiling test could have a material impact on future results of operations.

Oil and Gas Properties

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 twelve-month, first day of the month, average 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

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.

Other Property and Equipment

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 five years.

Accounts Receivable

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.

Deposit For Surety Bonds

Deposit For Surety Bonds

The deposit for surety bonds of $3.6 million and $8.3 million at December 31, 2018 and 2017, respectively, represent cash collateral paid with respect to the Company's surety bonds which secured its offshore decommissioning obligations.

Income Taxes

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 that 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 realizability 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

Revenue Recognition

The Company records natural gas and oil revenue in accordance with Accounting Standards Update ("ASU") 2014-09 "Revenue from Contracts with Customers". 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.

The Company's sources of revenue are oil, natural gas and natural gas liquids ("NGL") production from its oil and gas properties. Oil and natural gas production is typically sold to purchasers through monthly contracts at negotiated sales prices based on published market indices. The sale takes place at the wellhead for oil production and at the wellhead or gas processing plant for natural gas. NGL production is sold once natural gas is processed and the related liquids are removed at the processing plant. The contracts for sale of NGL production are with the processing plant with prices based on what the processing plant is able to receive from third party purchasers.

Sales of oil, natural gas and NGL production are recognized when the product is delivered and title transfers to the purchaser and payment is generally received one to two months after the sale has occurred.

Concentrations

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.

Derivatives Instruments

Derivative Instruments

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 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 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, 2018, the Company had no derivative instruments in place. See Note 8 for further discussion of the Company’s derivative instruments.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board ("FASB") issued ASU 2016-02, "Leases (Topic 842)," to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This ASU supersedes the lease requirements in Topic 840, Leases, and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within the Company’s consolidated statements of operations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to mineral leases for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including the first quarter of 2019. The Company will adopt this standard using the modified retrospective method applied to all leases that exist on January 1, 2019. The Company made certain elections allowing it not to reassess contracts that commenced prior to adoption and to not recognize right-of-use assets or lease liabilities for short-term leases. Upon adoption, the Company expects the right-to-use asset and lease liability reported on its consolidated financial statements to be immaterial.

In August 2017, the FASB issued ASU 2017-12, "Derivative and Hedging," to improve the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities in its consolidated financial statements and make certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. ASU 2017-12 is effective for public entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with earlier application permitted. The Company is currently evaluating the effect that this new standard may have on its consolidated financial statements.

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Organization and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Disaggregation of Revenue

The following table includes a disaggregation of revenue by product including the effects of hedges in place (in thousands):

	Year Ended December 31,
	2018		2017		2016
Total oil sales	$	21,027	$	31,258	$	20,614
Total gas sales	50,768		60,922		37,963
Total ngl sales	15,303		16,107		8,090
Total oil and gas sales	$	87,099	$	108,287	$	66,667

Schedule of significant concentration risk

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.

	Year Ended December 31,
	2018	2017	2016
Superior Natural Gas	26%	29%	14%
Shell Trading Company	21%	24%	23%
Texla Energy Management	16%	(a)	(a)
Harvest Pipeline Company	12%	(a)	(a)
Laclede Energy Resources	(a)	(a)	17%
BG Group	(a)	(a)	10%

(a) Less than 10 percent

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Voluntary Reorganization under Chapter 11 of the Bankruptcy Code (Tables)

12 Months Ended

Dec. 31, 2018

Reorganizations [Abstract]

Schedule Of Liabilities Subject To Compromise

Liabilities subject to compromise at December 31, 2018 consisted of the following (in thousands):            

	December 31, 2018
10% Senior PIK Notes due 2021	$	275,046
10% Senior Notes due 2021	9,427
Accrued interest	20,624
Accounts payable to vendors	874
Other long-term liabilities	510
Other accrued liabilities	2,724
Preferred stock dividend payable	14,649
Liabilities subject to compromise	$	323,854

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

A reconciliation between basic and diluted earnings per share computations

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, 2018	Loss(Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(13,919	)	25,581	$	(0.54	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(13,919	)	25,581	$	(0.54	)
For the Year Ended December 31, 2017	Loss(Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(11,776	)	21,330	$	(0.55	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(11,776	)	21,330	$	(0.55	)
For the Year Ended December 31, 2016	Loss(Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(96,245	)	18,354	$	(5.24	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(96,245	)	18,354	$	(5.24	)

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of share-based compensation

A detail of share-based compensation cost for the years ended December 31, 2018, 2017 and 2016 is as follows (in thousands):

	Year Ended December 31,
	2018			2017		2016
Stock options:
Incentive Stock Options (share settled)	$	407		$	820	$	206
Non-Qualified Stock Options (share settled)	94			387		164
Restricted stock (share settled)	465			197		1,073
Cash settled stock units	(241		)	245		244
Share-based compensation	$	725		$	1,649	$	1,687

Schedule of stock option valuation assumptions

The following table outlines the assumptions used in computing the fair value of stock options granted during 2017 and 2016. No such grants were made during 2018.    

	2017	2016
Dividend yield	—%	—%
Expected volatility	80.44%	62.0%-79.99%
Risk-free rate	1.925%	1.255%-2.09%
Expected term	6 years	6 years
Stock options granted	219,130	1,168,754
Wgtd. avg. grant date fair value per share	$1.28	$1.96
Fair value of grants	$280,000	$2,293,000

Schedule of stock options activity

The following table details stock option activity during the year ended December 31, 2018:

	Number of Options		Wgtd. Avg. Exercise  Price		Wgtd. Avg. Remaining  Life	Aggregate Intrinsic  Value (000’s)
Outstanding at beginning of year	1,608,646		$	6.20
Granted	—		—
Expired/cancelled/forfeited	(121,823	)	4.98
Exercised	—		—
Outstanding at end of year	1,486,823		6.34		7.03	$	—
Options exercisable at end of year	1,047,590		$	7.78	6.64	$	—

Schedule of stock option plans, by exercise price range

The following table summarizes information regarding stock options outstanding at December 31, 2018:

Range of	Options	Wgtd. Avg.	Wgtd. Avg.	Options	Wgtd. Avg.
Exercise	Outstanding	Remaining	Exercise	Exercisable	Exercise
Price	12/31/2018	Contractual Life	Price	12/31/2018	Price
$0.00-$2.37	250,477	8.43	$1.99	105,780	$2.07
$3.17-$4.36	1,013,663	7.68	$3.37	719,127	$3.36
$16.72-$19.52	68,190	4.42	$17.11	68,190	$17.11
$20.40-$30.32	154,493	1.73	$28.15	154,493	$28.15
	1,486,823			1,047,590	$7.78

Schedule of restricted stock units activity

The following table details restricted stock activity during the year ended December 31, 2018:

	Number of Shares		Wgtd. Avg. Fair Value  per Share
Outstanding at beginning of year	487,502		$1.87
Cancelled/forfeited	(34,946	)	$1.85
Lapse of restrictions	(37,500	)	$2.15
Outstanding at December 31, 2018	415,056		$1.85

The following table details MRSU and RSU activity during the year ended December 31, 2018:

	MRSU		RSU		Total
Outstanding at beginning of year	277,733		889,587		1,167,320
Granted	—		—		—
Expired/Cancelled/Forfeited	(270,269	)	(78,808	)	(349,077	)
Vested/Paid	(7,464	)	(323,374	)	(330,838	)
Outstanding at December 31, 2018	—		487,405		487,405

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Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Changes to the Company's asset retirement obligation liability

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

	Year Ended December 31,
	2018			2017
Asset retirement obligation, beginning of period	$	31,310		$	36,610
Liabilities incurred	7			574
Liabilities settled	(863		)	(3,364		)
Accretion expense	322			2,252
Revisions in estimated cash flows	(62		)	(4,514		)
Divestiture of oil and gas properties	(28,234		)	(248		)
Asset retirement obligation, end of period	2,480			31,310
Less: current portion of asset retirement obligation	(183		)	(687		)
Long-term asset retirement obligation	$	2,297		$	30,623

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Effect of cash flow hedges on the consolidated balance sheet

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at December 31, 2017:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
December 31, 2017	Derivative asset	$	1,174
December 31, 2017	Derivative liability	$	(731	)

Effect of cash flow hedges on the consolidated statement of operations

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for years ended December 31, 2018, 2017 and 2016:

Instrument	Amount of Gain (Loss) Recognized in Other Comprehensive Income			Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into Income
Commodity Derivatives at December 31, 2018	$	(990	)	Oil and gas sales	$	(622	)
Commodity Derivatives at December 31, 2017	$	6,654		Oil and gas sales	$	1,461
Commodity Derivatives at December 31, 2016	$	(4,447	)	Oil and gas sales	$	1,811

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Net Valuation of Derivatives

The following table summarizes the Company’s assets (liabilities) that are subject to fair value measurement on a recurring basis as of December 31, 2017 (in thousands):

	Fair Value Measurements Using
Instrument	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity Derivatives:
At December 31, 2017	$	—	$	443	$	—

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Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2016 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2015	$	947		$	—		$	947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	(4,447		)	—			(4,447		)
Income tax effect	1,654			(1,654		)	—
Net of tax	(2,793		)	(1,654		)	(4,447		)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(1,811		)	—			(1,811		)
Income tax effect	674			(113		)	561
Net of tax	(1,137		)	(113		)	(1,250		)
Net other comprehensive loss	(3,930		)	(1,767		)	(5,697		)
Balance as of December 31, 2016	$	(2,983	)	$	(1,767	)	$	(4,750	)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2017 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2016	$	(2,983	)	$	(1,767	)	$	(4,750	)
Other comprehensive income before reclassifications:				—
Change in fair value of derivatives	6,654			—			6,654
Income tax effect	(2,475		)	1,767			(708		)
Net of tax	4,179			1,767			5,946
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(1,461		)	—			(1,461		)
Income tax effect	543			—			543
Net of tax	(918		)	—			(918		)
Net other comprehensive loss	$	3,261		$	1,767		$	5,028
Balance as of December 31, 2017	$	278		$	—		$	278

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the year ended December 31, 2018 (in thousands):        

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2017	$	278
Other comprehensive income before reclassifications:
Change in fair value of derivatives	(990		)
Income tax effect	238
Net of tax	(752		)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	622
Income tax effect	(148		)
Net of tax	474
Net other comprehensive loss	(278		)
Balance as of December 31, 2018	$	—

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of Deferred Taxes

An analysis of the Company’s deferred tax assets and liabilities follows (amounts in thousands):

	December 31,
	2018			2017
Net operating loss carryforwards	$	86,046		$	78,541
Percentage depletion carryforward	6,011			5,701
Interest expense carryforward	10,540			—
Contributions carryforward and other	194			192
Temporary differences:
Oil and gas properties	3,673			8,279
Asset retirement obligation	602			7,602
Derivatives	—			(107		)
Share-based compensation	1,403			1,269
Original issue discount on debt exchanges	9,815			14,429
Other	432			—
Valuation allowance	(118,716		)	(115,906		)
Deferred tax asset (liability)	$	—		$	—

Income Tax Reconciliation

Income tax expense (benefit) for each of the years ended December 31, 2018, 2017 and 2016 was different than the amount computed using the federal statutory rate (21%) for the following reasons (amounts in thousands):

	For the Year Ended December 31,
	2018			2017			2016
Amount computed using the statutory rate	$	(1,973	)	$	(2,655	)	$	(31,623	)
Increase (reduction) in taxes resulting from:
Impact of rate change on deferred tax	—			64,915			—
State & local taxes	(1,731		)	(368		)	(2,000		)
Percentage depletion carryforward	(256		)	(66		)	(163		)
Non-deductible stock option expense (1)	98			305			77
Share-based compensation (2)	—			64			707
Restructuring costs	1,528			—			—
Other	93			(21		)	1,415
Change in valuation allowance	2,393			(63,123		)	32,130
Income tax expense (benefit)	$	152		$	(949	)	$	543

(1) Relates to compensation expense related to 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.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Lease Commitments

Future minimum lease commitments as of December 31, 2018 under these operating leases are as follows (in thousands):

2019	$	1,240
2020	1,173
2021	445
2022	431
2023	392
Thereafter	—
	$	3,681

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Supplementary Information on Oil and Gas Operations—Unaudited (Tables)

12 Months Ended

Dec. 31, 2018

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Costs incurred in oil and gas property acquisition

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)

	For the Year-Ended December 31,
	2018			2017			2016
Acquisition costs:
Proved	$	241		$	1,330		$	3,346
Unproved (1)	6,190			12,762			2,197
Divestiture of proved leasehold	(2,604		)	(4,795		)	(7,000		)
Exploration costs:
Proved	(51		)	9,466			715
Unproved	233			(287		)	603
Development costs (2)	(18,928		)	32,622			1,522
Capitalized general and administrative and interest costs	8,070			8,269			7,558
Total costs incurred	$	(6,849	)	$	59,367		$	8,941

	For the Year-Ended December 31,
	2018			2017			2016
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	$	(1,285,660	)	$	(1,243,286	)	$	(1,157,455	)
Provision for DD&A	(22,410		)	(31,667		)	(27,962		)
Ceiling test writedown	—			—			(40,304		)
Sale of proved properties and other (3)	6,478			(10,707		)	(17,565		)
Balance, end of year	$	(1,301,592	)	$	(1,285,660	)	$	(1,243,286	)
DD&A per Mcfe	$	1.05		$	1.15		$	1.19

(1) During 2017, the Company acquired approximately 24,600 gross acres for approximately $9.3 million in cash and 2.0 million shares of common stock. In total for 2017 and 2018, the Company has invested approximately $15.0 million in leasing costs and geological and engineering data.

(2) During 2018, the Company sold its Gulf of Mexico properties and removed approximately $28.2 million of future discounted asset retirement obligations, which was recorded as a reduction in the capitalized costs of oil and gas properties.

(3) During 2018, the Company sold its Gulf of Mexico properties, receiving no cash consideration and funding amounts related to the future abandonment costs for the properties and purchase price adjustments. During 2017, the Company sold its East Lake Verret assets for net proceeds of approximately $2.2 million and its East Texas saltwater disposal assets for net proceeds of $8.5 million. During 2016, the Company sold its remaining Oklahoma producing assets for net proceeds of $17.6 million.

Schedule of proved developed reserve quantities

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:

	Oil in MBbls		NGL in MMcfe		Natural Gas in MMcf		Total Reserves in MMcfe
Proved reserves as of December 31, 2015	1,806		34,826		132,344		178,004
Revisions of previous estimates	247		(4,380	)	(11,854	)	(14,748	)
Extensions, discoveries and other additions	—		—		1,485		1,485
Sale of reserves in place	(154	)	—		(24,834	)	(25,759	)
Production	(502	)	(3,871	)	(16,617	)	(23,501	)
Proved reserves as of December 31, 2016	1,397		26,575		80,524		115,481
Revisions of previous estimates	308		(7,269	)	381		(5,040	)
Extensions, discoveries and other additions	777		4,565		64,704		73,931
Purchase of producing properties	48		—		473		761
Sale of reserves in place	(90	)	—		(1,033	)	(1,573	)
Production	(592	)	(4,450	)	(19,611	)	(27,613	)
Proved reserves as of December 31, 2017	1,848		19,421		125,438		155,947
Revisions of previous estimates	130		(1,469	)	2,737		2,044
Extensions, discoveries and other additions	41		2,929		7,947		11,121
Sale of reserves in place	(507	)	(486	)	(13,945	)	(17,472	)
Production	(326	)	(3,373	)	(16,013	)	(21,335	)
Proved reserves as of December 31, 2018	1,186		17,022		106,164		130,305
Proved developed reserves
As of December 31, 2016	1,212		13,073		47,349		67,694
As of December 31, 2017	1,078		12,564		57,409		76,441
As of December 31, 2018	567		10,220		47,516		61,143
Proved undeveloped reserves
As of December 31, 2016	185		13,502		33,175		47,787
As of December 31, 2017	770		6,857		68,029		79,506
As of December 31, 2018	619		6,802		58,648		69,162

Standardized measure of discounted future cash flows

Standardized Measure

	December 31,
	2018			2017			2016
Future cash flows	$	482,766		$	539,244		$	299,035
Future production costs	(171,999		)	(184,171		)	(117,283		)
Future development costs	(73,258		)	(128,447		)	(83,720		)
Future income taxes	—			—			—
Future net cash flows	237,509			226,626			98,032
10% annual discount	(113,484		)	(99,329		)	(30,763		)
Standardized measure of discounted future net cash flows	$	124,025		$	127,297		$	67,269

Schedule of changes in standardized measure of discounted future net cash flows

Changes in Standardized Measure

	Year Ended December 31,
	2018			2017			2016
Standardized measure at beginning of year	$	127,297		$	67,269		$	127,685
Sales and transfers of oil and gas produced, net of production costs	(64,148		)	(70,362		)	(35,993		)
Changes in price, net of future production costs	18,542			53,516			(30,427		)
Extensions and discoveries, net of future production and development costs	2,983			50,977			864
Changes in estimated future development costs, net of development costs incurred during this period	16,241			17,144			26,356
Revisions of quantity estimates	2,755			(7,482		)	(14,889		)
Accretion of discount	12,730			6,727			12,769
Purchase of reserves in place	—			549			—
Sale of reserves in place	1,614			(1,305		)	(16,701		)
Changes in production rates (timing) and other	6,011			10,264			(2,395		)
Net increase (decrease) in standardized measure	(3,272		)	60,028			(60,416		)
Standardized measure at end of year	$	124,025		$	127,297		$	67,269

Average sales price and average production costs

The historical twelve-month, first day of the month, average prices of oil, gas and natural gas liquids used in determining standardized measure were:

	2018	2017	2016
Oil, $/Bbl	$68.71	$52.49	$40.85
Ngls, $/Mcfe	4.08	3.23	2.40
Natural Gas, $/Mcf	3.13	3.03	1.82

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Summarized Quarterly Financial Information - Unaudited (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Summarized quarterly financial information is as follows (amounts in thousands except per share data):

	Quarter Ended
	March 31			June 30			September 30			December 31
2018
Revenues	$	24,917		$	21,507		$	20,886		$	19,789
Income (loss) from operations	(821		)	(1,326		)	(3,657		)	701
Loss available to common stockholders	(2,212		)	(2,611		)	(4,979		)	$	(4,117	)
Loss per share:
Basic	$	(0.09	)	$	(0.10	)	$	(0.19	)	$	(0.16	)
Diluted	$	(0.09	)	$	(0.10	)	$	(0.19	)	$	(0.16	)
2017
Revenues	$	20,772		$	24,251		$	28,184		$	35,080
Income (loss) from operations	(3,633		)	(2,289		)	(1,885		)	221
Loss available to common stockholders	(4,918		)	(3,385		)	(3,085		)	(389		)
Loss per share:
Basic	$	(0.23	)	$	(0.16	)	$	(0.15	)	$	(0.02	)
Diluted	$	(0.23	)	$	(0.16	)	$	(0.15	)	$	(0.02	)

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Organization and Summary of Significant Accounting Policies - Other Property and Equipment (Details) - Furniture and Fixtures	12 Months Ended
	Dec. 31, 2018
Minimum
Property, Plant and Equipment [Line Items]
Useful life (in years)	3 years
Maximum
Property, Plant and Equipment [Line Items]
Useful life (in years)	5 years

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Organization and Summary of Significant Accounting Policies - Revenue Recognition (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenue receivable	$ 6,364				$ 15,340				$ 6,364	$ 15,340
Revenues	19,789	$ 20,886	$ 21,507	$ 24,917	$ 35,080	$ 28,184	$ 24,251	$ 20,772	87,099	108,287	$ 66,667
Total oil sales
Disaggregation of Revenue [Line Items]
Revenue receivable	1,100								1,100
Revenues									21,027	31,258	20,614
Total gas sales
Disaggregation of Revenue [Line Items]
Revenue receivable	4,800								4,800
Revenues									50,768	60,922	37,963
Total ngl sales
Disaggregation of Revenue [Line Items]
Revenue receivable	$ 500								500
Revenues									$ 15,303	$ 16,107	$ 8,090
Minimum
Disaggregation of Revenue [Line Items]
Revenue recognized, period									1 month
Maximum
Disaggregation of Revenue [Line Items]
Revenue recognized, period									2 months

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Organization and Summary of Significant Accounting Policies - Concentrations (Details) - Oil and Gas Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Superior Natural Gas
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	26.00%	29.00%	14.00%
Shell Trading Company
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	21.00%	24.00%	23.00%
Texla Energy Management
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	16.00%
Harvest Pipeline Company
Concentration Risk [Line Items]
Net oil and gas revenues (percent)	12.00%
Laclede Energy Resources
Concentration Risk [Line Items]
Net oil and gas revenues (percent)			17.00%
BG Group
Concentration Risk [Line Items]
Net oil and gas revenues (percent)			10.00%

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Organization and Summary of Significant Accounting Policies - Other Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deposit for surety bonds	$ 3,550	$ 8,300
Other Noncurrent Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deposit for surety bonds		$ 8,300

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Acquisitions and Divestitures (Details) $ in Thousands, shares in Millions			1 Months Ended	12 Months Ended
	Jan. 31, 2018 USD ($)	Dec. 20, 2017 USD ($) a	Jan. 31, 2018 USD ($)	Dec. 31, 2018 USD ($) shares	Dec. 31, 2017 USD ($)	Dec. 15, 2017 USD ($)	Apr. 17, 2017 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Decrease in asset retirement obligation liabilities related to divestiture of oil and gas properties				$ 28,234	$ 248
Deposit for surety bonds				3,550	$ 8,300
Interests in East Lake Verret Field
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration received from sale							$ 2,200
Saltwater Disposal Assets in East Texas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration received from sale						$ 8,500
Gulf of Mexico Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase commitment	$ 3,800		$ 3,800
Decrease in asset retirement obligation liabilities related to divestiture of oil and gas properties			$ 28,200
Proceeds from refunds related to disposal	4,500
Deposit for surety bonds				3,600
Austin Chalk Acreage
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acres acquired | a		24,600
Purchase price		$ 9,300		$ 15,000
Common shares issued in connection with acquisition | shares				2.0
Pro Forma | Gulf of Mexico Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Decrease in asset retirement obligation liabilities related to divestiture of oil and gas properties	$ 28,200

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Voluntary Reorganization under Chapter 11 of the Bankruptcy Code - Additional Information (Details) - Payment in Kind (PIK) Note - 10% Senior Secured PIK Notes due 2021 - USD ($) $ in Millions	Sep. 27, 2016	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Stated interest rate		10.00%	10.00%
PIK Interest
Class of Stock [Line Items]
Stated interest rate		10.00%
Cash interest payment due		$ 14.2
September Exchange and Consent Solicitation | PIK Interest
Class of Stock [Line Items]
Stated interest rate	1.00%
Basis spread on variable rate	9.00%

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Voluntary Reorganization under Chapter 11 of the Bankruptcy Code - Chapter 11 (Details) - USD ($)			12 Months Ended
	Feb. 08, 2019	Dec. 28, 2017	Dec. 31, 2018	Nov. 06, 2018	Dec. 31, 2017
Restructuring Cost and Reserve [Line Items]
Post petition professional fees relating to Chapter 11 Cases			$ 3,800,000
Reorganization items related to adjustments to certain claims relating to Chapter 11 Cases			500,000
Liabilities Subject to Compromise [Abstract]
Accrued interest			20,624,000
Accounts payable to vendors			874,000
Other long-term liabilities			510,000
Other accrued liabilities			2,724,000
Preferred stock dividend payable			14,649,000
Liabilities subject to compromise			$ 323,854,000		$ 0
10% Senior Secured Notes due 2021
Restructuring Cost and Reserve [Line Items]
New shares issued (in shares)		2,200,000
10% Senior Secured Notes due 2021 | Restructuring Support Agreement
Restructuring Cost and Reserve [Line Items]
Debt instrument, ownership percentage				81.83%
Stated interest rate				10.00%
10% Senior Secured PIK Notes due 2021 | Restructuring Support Agreement
Restructuring Cost and Reserve [Line Items]
Debt instrument, ownership percentage				84.76%
Stated interest rate				10.00%
Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Restructuring Cost and Reserve [Line Items]
Stated interest rate			10.00%		10.00%
Liabilities Subject to Compromise [Abstract]
10% Senior Secured Notes			$ 275,046,000
Senior Notes | 10% Senior Secured Notes due 2021
Restructuring Cost and Reserve [Line Items]
Stated interest rate			10.00%		10.00%
Liabilities Subject to Compromise [Abstract]
10% Senior Secured Notes			$ 9,427,000
Subsequent Event | Payment in Kind (PIK) Note | 10% Secured PIK Notes due 2024
Restructuring Cost and Reserve [Line Items]
Stated interest rate	10.00%
Principal amount	$ 80,000,000
Subsequent Event | Payment in Kind (PIK) Note | Former Holders Of Old Notes | 10% Secured PIK Notes due 2024 | Cancellation And Discharge Of Old Notes
Restructuring Cost and Reserve [Line Items]
Principal amount	80,000,000
Term Loan | Subsequent Event | Line of Credit | Exit Facility
Restructuring Cost and Reserve [Line Items]
Maximum borrowing capacity	$ 50,000,000
Class A Common Stock | Common Stock | Subsequent Event | Commitment To Backstop Exit Facility
Restructuring Cost and Reserve [Line Items]
New shares issued (in shares)	300,000
Class A Common Stock | Common Stock | Subsequent Event | 2019 Long Term Incentive Plan
Restructuring Cost and Reserve [Line Items]
Number of shares reserved for issuance (in shares)	1,344,000
Class A Common Stock | Common Stock | Subsequent Event | Former Holders Of Old Notes | Cancellation And Discharge Of Old Notes
Restructuring Cost and Reserve [Line Items]
New shares issued (in shares)	8,900,000
Class B Common Stock | Common Stock | Subsequent Event | Class B Holder
Restructuring Cost and Reserve [Line Items]
New shares issued (in shares)	1
Class C Common Stock | Common Stock | Subsequent Event | Class C Holder
Restructuring Cost and Reserve [Line Items]
New shares issued (in shares)	1

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Equity - Common Stock (Details) shares in Millions	12 Months Ended
	Dec. 31, 2018 shares
Austin Chalk Acreage
Class of Stock [Line Items]
Common shares issued in connection with acquisition	2.0

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Equity - Convertible Preferred Stock (Details)	12 Months Ended
	Dec. 31, 2018 USD ($) payment $ / shares Rate shares	Dec. 31, 2017 USD ($) shares
Class of Stock [Line Items]
Preferred stock, shares outstanding | shares	1,495,000	1,495,000
Dividends payable | $	$ 0	$ 10,278,000
Series B Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares outstanding | shares	1,495,000
Series B cumulative convertible perpetual preferred stock interest rate | Rate	6.875%
Number of deferred dividend payments | payment	11
Number of trading days	20 days
Number of consecutive trading days	30 years
Closing price as percentage of conversion price	130.00%
Series B Preferred Stock converted into common stock (in shares) | shares	0.860825
Initial conversion price of common stock (in usd per share) | $ / shares	$ 58.08
Trading day averaging period for determining conversion value	20 days
Conversion rate numerator for Preferred Stock | $	$ 50
Other long-term liabilities | Series B Preferred Stock
Class of Stock [Line Items]
Dividends payable | $	$ 14,600,000

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Earnings Per Share - Reconciliation Between Basic and Diluted EPS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
A reconciliation between basic and diluted earnings per share computations
Net loss available to common stockholders	$ (4,117)	$ (4,979)	$ (2,611)	$ (2,212)	$ (389)	$ (3,085)	$ (3,385)	$ (4,918)	$ (13,919)	$ (11,776)	$ (96,245)
Net loss available to common stockholders (in shares)									25,581	21,330	18,354
Net loss available to common stockholders (in usd per share)	$ (0.16)	$ (0.19)	$ (0.10)	$ (0.09)	$ (0.02)	$ (0.15)	$ (0.16)	$ (0.23)	$ (0.54)	$ (0.55)	$ (5.24)
Stock options, effect of dilutive securities									$ 0	$ 0
Stock options, effect of dilutive securities, (in shares)									0	0
Attributable to participating securities									$ 0	$ 0
Restricted stock, effect of dilutive securities (in shares)									0	0	0
DILUTED EPS, Loss									$ (13,919)	$ (11,776)	$ (96,245)
DILUTED EPS (in shares)									25,581	21,330	18,354
DILUTED EPS, per share amount (in usd per share)	$ (0.16)	$ (0.19)	$ (0.10)	$ (0.09)	$ (0.02)	$ (0.15)	$ (0.16)	$ (0.23)	$ (0.54)	$ (0.55)	$ (5.24)

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Earnings Per Share - Additional Information (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Common stock issuable on conversion (in shares)	2.0	1.6	0.9
Convertible preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Common stock issuable on conversion (in shares)	1.3

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Share-Based Compensation - Share based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Summary of share-based compensation
Share-based compensation	$ 725	$ 1,649	$ 1,687
Incentive Stock Options (share settled)
Summary of share-based compensation
Share-based compensation	407	820	206
Non-Qualified Stock Options (share settled)
Summary of share-based compensation
Share-based compensation	94	387	164
Restricted stock (share settled)
Summary of share-based compensation
Share-based compensation	465	197	1,073
Cash settled stock units
Summary of share-based compensation
Share-based compensation	$ (241)	$ 245	$ 244

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Share-Based Compensation - Narrative (Details) $ / shares in Units, $ in Thousands	1 Months Ended		12 Months Ended
	Nov. 30, 2017 shares	Nov. 30, 2014 shares	Dec. 31, 2018 USD ($) company shares	Dec. 31, 2017 USD ($) $ / shares shares	Dec. 31, 2016 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation costs capitalized in period				$ 103	$ 106
Tax benefit from compensation expense			$ 101	270	512
Deferred tax assets, operating loss carryforwards			86,046	78,541
Total compensation cost not yet recognized			400
Fair value of stock options that vested during period			$ 1,200	$ 1,600	400
Vested/Paid (in shares) | shares			(330,838)
Granted (in shares) | shares			0
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period until vesting			1 year
Granted (in dollars per share) | $ / shares				$ 1.87
Total value of stock that vested			$ 100	$ 1,300	$ 2,400
Vested/Paid (in shares) | shares			(37,500)
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period			3 years
Period until vesting			1 year
Award expiration period			10 years
Cash settled stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period			3 years
Total value of stock that vested			$ 24	$ 59
Vested/Paid (in shares) | shares			(323,374)	(31,703)
Granted (in shares) | shares			0
Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual vesting percentage			33.33%
Vested/Paid (in shares) | shares			(7,464)
Granted (in shares) | shares	270,269	60,767	0
Evaluation period (in days)			20 days
Number of peer group companies | company			12
Earned at end of performance period, percent				50.00%
Restricted Stock Units (RSUs) And Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred compensation share-based arrangements, liability, current				$ 300
Prior to 2011 | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Annual vesting percentage			25.00%
Minimum | Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earning percentage			0.00%
Maximum | Market Based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Earning percentage			200.00%
Accounting Standards Update 2016-09
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred tax assets, operating loss carryforwards				$ 4,700

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Share-Based Compensation - Fair Value Assumption (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Stock options granted (shares)	0
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Dividend yield		0.00%	0.00%
Expected volatility		80.44%
Risk-free rate		1.925%
Expected term		6 years	6 years
Stock options granted (shares)	0	219,130	1,168,754
Weighted average grant date fair value (usd per share)		$ 1.28	$ 1.96
Fair value of grants		$ 280	$ 2,293
Minimum | Stock Options
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility			62.00%
Risk-free rate			1.255%
Maximum | Stock Options
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility			79.99%
Risk-free rate			2.09%

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Share-Based Compensation - Activity (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) $ / shares shares
Number of Options
Outstanding at beginning of year (in shares) | shares	1,608,646
Granted (in shares) | shares	0
Expired/canceled/forfeited (in shares) | shares	(121,823)
Exercised (in shares) | shares	0
Outstanding at end of year (in shares) | shares	1,486,823
Wgtd. Avg. Exercise Price
Outstanding at beginning of year (in dollars per share) | $ / shares	$ 6.20
Granted (in dollars per share) | $ / shares	0.00
Expired/canceled/forfeited (in dollars per share) | $ / shares	4.98
Exercised (in dollars per share) | $ / shares	0.00
Outstanding at end of year (in dollars per share) | $ / shares	$ 6.34
Additional Disclosures
Options exercisable at end of year (in shares) | shares	1,047,590
Options exercisable at end of year (usd per share) | $ / shares	$ 7.78
Outstanding, remaining contractual term	7 years 11 days
Exercisable, remaining contractual term	6 years 7 months 21 days
Outstanding, intrinsic value | $	$ 0
Exercisable, intrinsic value | $	$ 0

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Share-Based Compensation - Exercise Prices (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Outstanding at end of year (in shares)	1,486,823	1,608,646
Wgtd. Avg. Remaining Contractual Life	7 years 11 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 6.34	$ 6.20
Options exercisable (in shares)	1,047,590
Wgtd. Avg. Exercise Price (usd per share)	$ 7.78
$0.00-$2.37
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	0
Exercise price range, upper range limit	$ 2.37
Outstanding at end of year (in shares)	250,477
Wgtd. Avg. Remaining Contractual Life	8 years 5 months 5 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 1.99
Options exercisable (in shares)	105,780
Wgtd. Avg. Exercise Price (usd per share)	$ 2.07
$3.17-$4.36
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	3.17
Exercise price range, upper range limit	$ 4.36
Outstanding at end of year (in shares)	1,013,663
Wgtd. Avg. Remaining Contractual Life	7 years 8 months 5 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 3.37
Options exercisable (in shares)	719,127
Wgtd. Avg. Exercise Price (usd per share)	$ 3.36
$16.72-$19.52
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	16.72
Exercise price range, upper range limit	$ 19.52
Outstanding at end of year (in shares)	68,190
Wgtd. Avg. Remaining Contractual Life	4 years 5 months 1 day
Wgtd. Avg. Exercise Price (in dollars per share)	$ 17.11
Options exercisable (in shares)	68,190
Wgtd. Avg. Exercise Price (usd per share)	$ 17.11
$20.40-$30.32
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price range, lower range limit	20.40
Exercise price range, upper range limit	$ 30.32
Outstanding at end of year (in shares)	154,493
Wgtd. Avg. Remaining Contractual Life	1 year 8 months 23 days
Wgtd. Avg. Exercise Price (in dollars per share)	$ 28.15
Options exercisable (in shares)	154,493
Wgtd. Avg. Exercise Price (usd per share)	$ 28.15

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Share-Based Compensation - Restricted Stock (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Number of Shares
Outstanding at beginning of year (in shares)	1,167,320
Canceled/forfeited (in shares)	(349,077)
Lapse of restrictions (in shares)	(330,838)
Outstanding at end of year (in shares)	487,405	1,167,320
Restricted Stock
Number of Shares
Outstanding at beginning of year (in shares)	487,502
Canceled/forfeited (in shares)	(34,946)
Lapse of restrictions (in shares)	(37,500)
Outstanding at end of year (in shares)	415,056	487,502
Wgtd. Avg. Fair Value per Share
Outstanding at beginning of year (in dollars per share)	$ 1.87
Cancelled/forfeited (in dollars per share)	1.85
Lapse of restrictions (in dollars per share)	2.15
Outstanding at end of year (in dollars per share)	$ 1.85	$ 1.87
Additional Information
Weighted average grant date fair value (in dollars per share)		$ 1.87
Total value of stock that vested	$ 0.1	$ 1.3	$ 2.4

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Share-Based Compensation - Restricted Stock Units (Details) - shares	1 Months Ended		12 Months Ended
	Nov. 30, 2017	Nov. 30, 2014	Dec. 31, 2018	Dec. 31, 2017
Number of Shares
Outstanding at beginning of year (in shares)			1,167,320
Granted (in shares)			0
Canceled/forfeited (in shares)			(349,077)
Vested/Paid (in shares)			(330,838)
Outstanding at end of year (in shares)			487,405	1,167,320
MRSU
Number of Shares
Outstanding at beginning of year (in shares)			277,733
Granted (in shares)	270,269	60,767	0
Canceled/forfeited (in shares)			(270,269)
Vested/Paid (in shares)			(7,464)
Outstanding at end of year (in shares)			0	277,733
RSU
Number of Shares
Outstanding at beginning of year (in shares)			889,587
Granted (in shares)			0
Canceled/forfeited (in shares)			(78,808)
Vested/Paid (in shares)			(323,374)	(31,703)
Outstanding at end of year (in shares)			487,405	889,587

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Asset Retirement Obligation (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Changes to the Company's asset retirement obligation liability
Asset retirement obligation, beginning of period	$ 31,310	$ 31,310	$ 36,610
Liabilities incurred		7	574
Liabilities settled		(863)	(3,364)
Accretion expense		322	2,252
Revisions in estimated cash flows		(62)	(4,514)
Divestiture of oil and gas properties		(28,234)	(248)
Asset retirement obligation, end of period		2,480	31,310
Less: current portion of asset retirement obligation		(183)	(687)
Long-term asset retirement obligation		$ 2,297	$ 30,623
Gulf of Mexico Properties
Changes to the Company's asset retirement obligation liability
Divestiture of oil and gas properties	$ (28,200)

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Derivative Instruments - Effect of Cash Flow Hedges on the Balance Sheet (Details) - Designated as Hedging Instrument - Commodity Derivatives $ in Thousands	Dec. 31, 2017 USD ($)
Derivative asset
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Derivative asset	$ 1,174
Derivative liability
Effect of Cash Flow Hedges on the Consolidated Balance Sheet
Derivative liability	$ (731)

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Derivative Instruments - Effect of Cash Flow Hedges on the Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income	$ (278)	$ 5,028	$ (5,697)
Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Other Comprehensive Income	(990)	6,654	(4,447)
Designated as Hedging Instrument | Oil and gas sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified into Income	$ (622)	$ 1,461	$ 1,811

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Derivative Instruments - Narrative (Details) - USD ($)		12 Months Ended
	Jun. 14, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Gas hedges
Derivatives, Fair Value [Line Items]
Net settlement of hedges		$ 800,000	$ 1,500,000	$ 1,800,000
Crude Oil
Derivatives, Fair Value [Line Items]
Net settlement of hedges		$ (1,427,540)	$ 0	$ 0
Koch Supply & Trading LP
Derivatives, Fair Value [Line Items]
Net settlement of hedges	$ 500,000

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Fair Value Measurements - Commodity Derivatives at Fair Value (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Quoted Prices in Active Markets (Level 1)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity derivatives	$ 0
Significant Other Observable Inputs (Level 2)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity derivatives	443
Significant Unobservable Inputs (Level 3)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity derivatives	$ 0

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Fair Value Measurements - Fair Value and Carrying Value (Details) - Fair Value - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Senior Notes | 2021 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	$ 2.8	$ 7.3
Payment in Kind (PIK) Note | 2021 PIK Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	$ 82.5	$ 198.7

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Long-Term Debt - Narrative (Details) shares in Millions							12 Months Ended
	Sep. 14, 2018 USD ($)	Aug. 31, 2018 USD ($)	Dec. 28, 2017 USD ($) shares	Mar. 31, 2017 USD ($)	Sep. 27, 2016 USD ($) payment shares	Feb. 17, 2016 USD ($) shares	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Nov. 06, 2018	Sep. 30, 2018	Oct. 17, 2016 USD ($)	Jan. 14, 2016	Jul. 03, 2013 USD ($)	Aug. 19, 2010 USD ($)
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt							$ 0	$ 403,000	$ 0
10% Senior Unsecured Notes Due 2017
Debt Instrument [Line Items]
Repayments of debt				$ 22,800,000
10% Senior Unsecured Notes Due 2017 | Senior Notes
Debt Instrument [Line Items]
Principal amount														$ 200,000,000	$ 150,000,000
Stated interest rate														10.00%	10.00%
Long-term debt						$ 135,600,000
10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Debt extinguished			$ 4,800,000
Common shares issued related to extinguishment of debt | shares			2.2
10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate							10.00%	10.00%
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Stated interest rate							10.00%	10.00%
10% Senior Secured PIK Notes due 2021 | PIK Interest | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Stated interest rate							10.00%
10 Percent Senior Notes And PIK Notes Due 2021 | Senior Notes
Debt Instrument [Line Items]
Loan forbearance, non payment of interest, period	30 days
Private Exchange Offer and Consent Solicitation
Debt Instrument [Line Items]
Repayments of debt						53,600,000
Private Exchange Offer and Consent Solicitation | 10% Senior Unsecured Notes Due 2017 | Senior Notes
Debt Instrument [Line Items]
Debt conversion, original debt, amount						$ 214,400,000
Debt conversion, original debt, percent of total						61.00%
Gain (loss) on extinguishment of debt						$ 0
Private Exchange Offer and Consent Solicitation | 10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate													10.00%
Debt conversion, converted instrument, amount						144,700,000
Long-term debt						$ 13,900,000
Private Exchange Offer and Consent Solicitation | 10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Stated interest rate											10.00%
Excess (shortfall) carrying value					$ (600,000)
September Exchange and Consent Solicitation | 10% Senior Unsecured Notes Due 2017 | Senior Notes
Debt Instrument [Line Items]
Debt conversion, original debt, amount					$ 113,000,000
Debt conversion, original debt, percent of total					83.00%
Long-term debt					$ 22,700,000
September Exchange and Consent Solicitation | 10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Debt conversion, original debt, amount					$ 130,500,000
Debt conversion, original debt, percent of total					90.00%
Long-term debt					$ 14,200,000
September Exchange and Consent Solicitation | 10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Debt conversion, converted instrument, amount					$ 243,500,000
Number of interest payments with variable rate | payment					3
September Exchange and Consent Solicitation | 10% Senior Secured PIK Notes due 2021 | PIK Interest | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Stated interest rate					1.00%
Adjusted LIBO rate (as a percent)					9.00%
Common Stock | Private Exchange Offer and Consent Solicitation
Debt Instrument [Line Items]
Debt conversion, converted instrument, shares issued | shares					3.5	1.1
Term Loan | Line of Credit
Debt Instrument [Line Items]
Deferred finance costs							$ (300,000)	$ (2,000,000)
Term Loan | Loan Agreement | Line of Credit
Debt Instrument [Line Items]
Repayments of debt		$ 32,500,000
Term Loan | Multidraw Term Loan Agreement | Line of Credit
Debt Instrument [Line Items]
Remaining borrowing capacity							$ 0
Long-term debt		$ 50,000,000
Revolving credit facility												$ 50,000,000
2021 Notes Supporting Holders | Forbearance Agreement | Senior Notes
Debt Instrument [Line Items]
Long-term debt	$ 7,300,000
Outstanding principal amount, percent	77.90%
2021 PIK Notes Supporting Holders | Forbearance Agreement | Payment in Kind (PIK) Note
Debt Instrument [Line Items]
Long-term debt	$ 194,600,000
Outstanding principal amount, percent	70.70%
Restructuring Support Agreement | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Stated interest rate										10.00%
Restructuring Support Agreement | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Stated interest rate										10.00%

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Long-Term Debt - Face Value to Carrying Value Reconciliation (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Feb. 17, 2016	Jul. 03, 2013	Aug. 19, 2010
Senior Notes | 10% Senior Unsecured Notes Due 2017
Debt Instrument [Line Items]
Principal amount				$ 200,000,000	$ 150,000,000
Long-term debt			$ 135,600,000
Term Loan | Line of Credit
Debt Instrument [Line Items]
Unamortized deferred finance costs	$ (300,000)	$ (2,000,000)

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Long-Term Debt - Exit Facility (Details) - Subsequent Event	Feb. 08, 2019 USD ($)
Payment in Kind (PIK) Note | 10% Secured PIK Notes due 2024
Debt Instrument [Line Items]
Stated interest rate	10.00%
Principal amount	$ 80,000,000
Payment in Kind (PIK) Note | 10% Secured PIK Notes due 2024 | February 8, 2019 to February 7, 2020
Debt Instrument [Line Items]
Redemption price, percentage	102.00%
Payment in Kind (PIK) Note | 10% Secured PIK Notes due 2024 | February 8, 2020 to February 7, 2021
Debt Instrument [Line Items]
Redemption price, percentage	101.00%
Payment in Kind (PIK) Note | 10% Secured PIK Notes due 2024 | February 8, 2021 and thereafter
Debt Instrument [Line Items]
Redemption price, percentage	100.00%
Payment in Kind (PIK) Note | 10% Secured PIK Notes due 2024 | Upon occurrence of change of control events
Debt Instrument [Line Items]
Redemption price, percentage	101.00%
Term Loan | Line of Credit | Exit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 50,000,000
Present value of estimated future net revenues, discount percent	10.00%
Ratio of present value of estimated future net revenues to sum of outstanding term loans and commitments	1.5
Term Loan | Line of Credit | Exit Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Stated interest rate	7.50%
Term Loan | Line of Credit | Exit Facility | Base Rate
Debt Instrument [Line Items]
Stated interest rate	6.50%

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Related Party Transactions (Details) - Officer $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) party	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Related Party Transaction [Line Items]
Number of related parties | party	2
Mr. Goodson
Related Party Transaction [Line Items]
Proceeds from affiliates	$ 0	$ (107)	$ (15)
Mr. Green
Related Party Transaction [Line Items]
Payments of distributions to related parties	$ 20	$ 41	$ 25

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Ceiling Test Write-down (Details)	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) $ / mcf $ / bbl $ / Mcfe
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Rate for discounting future cash flows	10.00%
Ceiling test write-down	$ 0	$ 0	$ 40,304,000
Mcf of natural gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average sales prices (usd per unit) | $ / mcf			2.51
Barrel of oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average sales prices (usd per unit) | $ / bbl			40.85
Mcfe of natural gas liquids
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average sales prices (usd per unit) | $ / Mcfe			1.82
Cash Flow Hedging | Commodity Contract
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Ceiling test write-downs decrease			$ 8,000,000

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Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	$ (248,935)	$ (251,095)	$ (163,067)
Other comprehensive income before reclassifications:
Change in fair value of derivatives		6,654	(4,447)
Income tax effect		(708)	0
Net of tax		5,946	(4,447)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales		(1,461)	(1,811)
Income tax effect		543	561
Net of tax		(918)	(1,250)
Net other comprehensive loss		5,028	(5,697)
Ending balance	(262,167)	(248,935)	(251,095)
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	278	(2,983)	947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	(990)	6,654	(4,447)
Income tax effect	238	(2,475)	1,654
Net of tax	(752)	4,179	(2,793)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	622	(1,461)	(1,811)
Income tax effect	(148)	543	674
Net of tax	474	(918)	(1,137)
Net other comprehensive loss	(278)	3,261	(3,930)
Ending balance	0	278	(2,983)
Change in Valuation Allowance
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	0	(1,767)	0
Other comprehensive income before reclassifications:
Change in fair value of derivatives		0	0
Income tax effect		1,767	(1,654)
Net of tax		1,767	(1,654)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales		0	0
Income tax effect		0	(113)
Net of tax		0	(113)
Net other comprehensive loss		1,767	(1,767)
Ending balance		0	(1,767)
Total
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	278	(4,750)	947
Amounts reclassified from accumulated other comprehensive income:
Ending balance	$ 0	$ 278	$ (4,750)

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Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes (Textual) [Abstract]
Income taxes at a statutory rate		35.00%	35.00%
Cumulative loss period	3 years
Valuation allowance	$ 118,716	$ 115,906
Tax Cuts and Jobs Act, provisional Income tax expense (benefit)		64,900
Deferred tax assets, operating loss carryforwards	86,046	78,541
Operating loss carryforwards	355,400
Operating loss carryforwards, not subject to expiration, subject to limitation	20,300
Depletion Deduction
Income Taxes (Textual) [Abstract]
Tax credit carryforward	28,200
Deductible Interest Expense [Member]
Income Taxes (Textual) [Abstract]
Tax credit carryforward	43,900
Louisiana
Income Taxes (Textual) [Abstract]
Operating loss carryforwards	180,700
Operating loss carryforwards subject to expiration	300
Accounting Standards Update 2016-09
Income Taxes (Textual) [Abstract]
Deferred tax assets, operating loss carryforwards		$ 4,700
Tax Year 2025
Income Taxes (Textual) [Abstract]
Operating loss carryforwards subject to expiration	6,900
Tax Year 2037
Income Taxes (Textual) [Abstract]
Operating loss carryforwards subject to expiration	$ 328,200

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Income Taxes - Deferred Tax Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Net operating loss carryforwards	$ 86,046	$ 78,541
Percentage depletion carryforward	6,011	5,701
Interest expense carryforward	10,540	0
Contributions carryforward and other	194	192
Oil and gas properties	3,673	8,279
Asset retirement obligation	602	7,602
Derivatives	0	(107)
Share-based compensation	1,403	1,269
Original issue discount on debt exchanges	9,815	14,429
Other	432	0
Valuation allowance	(118,716)	(115,906)
Deferred tax asset (liability)	$ 0	$ 0

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Income Taxes - Income Tax Expense (Benefit) Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Amount computed using the statutory rate	$ (1,973)	$ (2,655)	$ (31,623)
Impact of rate change on deferred tax	0	64,915	0
State & local taxes	(1,731)	(368)	(2,000)
Percentage depletion carryforward	(256)	(66)	(163)
Non-deductible stock option expense	98	305	77
Share-based compensation	0	64	707
Restructuring costs	1,528	0	0
Other	93	(21)	1,415
Change in valuation allowance	2,393	(63,123)	32,130
Income tax expense (benefit)	$ 152	$ (949)	$ 543

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Commitments and Contingencies - Litigation (Details) - Class Action Lawsuits, General Unsecured Claims - Pending Litigation	Oct. 01, 2016 claim	Dec. 31, 2018 USD ($)
Loss Contingencies [Line Items]
Number of claims filed | claim	2
Maximum
Loss Contingencies [Line Items]
Estimate of possible loss | $		$ 400,000

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Commitments and Contingencies - Lease Commitments (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($)
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2019	$ 1,240
2020	1,173
2021	445
2022	431
2023	392
Thereafter	0
Total	3,681
Operating leases rent expense	1,500
Lease amendment, decrease in rent expense	$ 1,300

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Supplementary Information on Oil and Gas Operations—Unaudited - Costs Incurred (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) $ / Mcfe	Dec. 31, 2017 USD ($) $ / Mcfe	Dec. 31, 2016 USD ($) $ / Mcfe
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Acquisition costs: Proved	$ 241	$ 1,330	$ 3,346
Acquisition costs: Unproved	6,190	12,762	2,197
Divestiture of proved leasehold	(2,604)	(4,795)	(7,000)
Exploration costs: Proved	(51)	9,466	715
Exploration costs: Unproved	233	(287)	603
Development costs (2)	(18,928)	32,622	1,522
Capitalized general and administrative and interest costs	8,070	8,269	7,558
Total costs incurred	(6,849)	59,367	8,941
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	(1,285,660)	(1,243,286)	(1,157,455)
Provision for DD&A	(22,410)	(31,667)	(27,962)
Ceiling test writedown	0	0	(40,304)
Sale of proved properties and other	6,478	(10,707)	(17,565)
Balance, end of year	$ (1,301,592)	$ (1,285,660)	$ (1,243,286)
DD&A per Mcfe (usd per mcfe) | $ / Mcfe	1.05	1.15	1.19

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Supplementary Information on Oil and Gas Operations—Unaudited - Investment in Oil and Gas Properties (Details) $ in Thousands, shares in Millions			1 Months Ended	12 Months Ended
	Jan. 31, 2018 USD ($)	Dec. 20, 2017 USD ($) a	Jan. 31, 2018 USD ($)	Dec. 31, 2018 USD ($) shares	Dec. 31, 2017 USD ($) Wells	Dec. 31, 2016 USD ($)	Dec. 15, 2017 USD ($)	Apr. 17, 2017 USD ($)
Reserve Quantities [Line Items]
Decrease in asset retirement obligation liabilities related to divestiture of oil and gas properties				$ 28,234	$ 248
Sale of oil and gas properties				(6,478)	10,707	$ 25,482
Unevaluated oil and gas properties				23,500	21,900
Interest costs capitalized				$ 1,800	1,600	900
Expected period to evaluate existing unevaluated properties				3 years
Unevaluated costs expected to be evaluated in 2017				$ 2,700
Uncompleted Wells Equipment and Facilities
Reserve Quantities [Line Items]
Unevaluated oil and gas properties				900	$ 700
Exploratory wells drilled, unevaluated | Wells					2
Incurred In 2017
Reserve Quantities [Line Items]
Unevaluated oil and gas properties				$ 7,400
Percentage of unevaluated costs capitalized in period				32.00%
Incurred In 2016
Reserve Quantities [Line Items]
Unevaluated oil and gas properties					$ 13,900
Percentage of unevaluated costs capitalized in period					59.00%
Incurred Prior 2016
Reserve Quantities [Line Items]
Unevaluated oil and gas properties						$ 2,200
Percentage of unevaluated costs capitalized in period						9.00%
Austin Chalk Acreage
Reserve Quantities [Line Items]
Acres acquired | a		24,600
Purchase price		$ 9,300		$ 15,000
Common shares issued in connection with acquisition | shares				2.0
Oklahoma Assets
Reserve Quantities [Line Items]
Consideration received from sale						$ 17,600
Gulf of Mexico Properties
Reserve Quantities [Line Items]
Decrease in asset retirement obligation liabilities related to divestiture of oil and gas properties			$ 28,200
Unevaluated oil and gas properties				$ 5,500
Percentage of unevaluated costs capitalized in period				25.00%
Interests in East Lake Verret Field
Reserve Quantities [Line Items]
Consideration received from sale								$ 2,200
Saltwater Disposal Assets in East Texas
Reserve Quantities [Line Items]
Consideration received from sale							$ 8,500
Pro Forma | Gulf of Mexico Properties
Reserve Quantities [Line Items]
Decrease in asset retirement obligation liabilities related to divestiture of oil and gas properties	$ 28,200

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Supplementary Information on Oil and Gas Operations—Unaudited - Proved Reserves (Details) Mcfe in Thousands, MMcf in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2018 Mcfe MBbls MMcf	Dec. 31, 2017 Mcfe MBbls MMcf	Dec. 31, 2016 Mcfe MBbls MMcf
Oil
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance | MBbls	1,848	1,397	1,806
Revisions of previous estimates | MBbls	130	308	247
Extensions, discoveries and other additions | MBbls	41	777	0
Purchase of producing properties | MBbls		48
Sale of reserves in place | MBbls	(507)	(90)	(154)
Production | MBbls	(326)	(592)	(502)
Proved reserves ending balance | MBbls	1,186	1,848	1,397
Proved developed reserves | MBbls	567	1,078	1,212
Proved undeveloped reserve | MBbls	619	770	185
Mcfe of natural gas liquids
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	19,421	26,575	34,826
Revisions of previous estimates	(1,469)	(7,269)	(4,380)
Extensions, discoveries and other additions	2,929	4,565	0
Purchase of producing properties		0
Sale of reserves in place	(486)	0	0
Production	(3,373)	(4,450)	(3,871)
Proved reserves, ending balance	17,022	19,421	26,575
Proved undeveloped reserve	10,220	12,564	13,073
Proved developed reserves	6,802	6,857	13,502
Natural Gas
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves beginning balance | MMcf	125,438	80,524	132,344
Revisions of previous estimates | MMcf	2,737	381	(11,854)
Extensions, discoveries and other additions | MMcf	7,947	64,704	1,485
Purchase of producing properties | MMcf		473
Sale of reserves in place | MMcf	(13,945)	(1,033)	(24,834)
Production | MMcf	(16,013)	(19,611)	(16,617)
Proved reserves ending balance | MMcf	106,164	125,438	80,524
Proved developed reserves | MMcf	47,516	57,409	47,349
Proved undeveloped reserve | MMcf	58,648	68,029	33,175
Oil and Natural Gas Reserves
Proved Developed and Undeveloped Reserves [Abstract]
Proved reserves, ending balance	155,947	115,481	178,004
Revisions of previous estimates	2,044	(5,040)	(14,748)
Extensions, discoveries and other additions	11,121	73,931	1,485
Purchase of producing properties		761
Sale of reserves in place	(17,472)	(1,573)	(25,759)
Production	(21,335)	(27,613)	(23,501)
Proved reserves, ending balance	130,305	155,947	115,481
Proved undeveloped reserve	61,143	76,441	67,694
Proved developed reserves	69,162	79,506	47,787

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Supplementary Information on Oil and Gas Operations—Unaudited - Average Price and Text (Details) Mcfe in Thousands, MMcf in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2018 Mcfe Wells $ / mcf $ / bbl $ / Mcfe MBbls MMcf	Dec. 31, 2017 Mcfe Wells $ / mcf $ / bbl $ / Mcfe MBbls MMcf	Dec. 31, 2016 Mcfe Wells $ / mcf $ / bbl $ / Mcfe MBbls MMcf
Reserve Quantities [Line Items]
Company drilling success rate	100.00%	100.00%	100.00%
Gross wells drilled | Wells	2	8	5
Oil
Reserve Quantities [Line Items]
Number of Bcfe additions | MBbls	41	777	0
Consolidated oil and gas production costs per unit of production | $ / bbl	68.71	52.49	40.85
Mcfe of natural gas liquids
Reserve Quantities [Line Items]
Extensions, discoveries and other additions of Bcfe	2,929	4,565	0
Consolidated oil and gas production costs per unit of production | $ / Mcfe	4.08	3.23	2.40
Oil and Natural Gas Reserves
Reserve Quantities [Line Items]
Increase in proved developed and undeveloped reserves	(16.00%)	35.04646%	(35.12449%)
Extensions, discoveries and other additions of Bcfe	11,121	73,931	1,485
Natural Gas
Reserve Quantities [Line Items]
Number of Bcfe additions | MMcf	7,947	64,704	1,485
Consolidated oil and gas production costs per unit of production | $ / mcf	3.13	3.03	1.82
Gulf of Mexico Properties | Oil and Natural Gas Reserves
Reserve Quantities [Line Items]
Removal of Bcfe	10,148
Certain PUDs In East Texas | Oil and Natural Gas Reserves
Reserve Quantities [Line Items]
Removal of Bcfe	7,324

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Supplementary Information on Oil and Gas Operations—Unaudited - Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows [Abstract]
Future cash flows	$ 482,766	$ 539,244	$ 299,035
Future production costs	(171,999)	(184,171)	(117,283)
Future development costs	(73,258)	(128,447)	(83,720)
Future income taxes	0	0	0
Future net cash flows	237,509	226,626	98,032
10% annual discount	(113,484)	(99,329)	(30,763)
Standardized measure of discounted future net cash flows	$ 124,025	$ 127,297	$ 67,269	$ 127,685

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Supplementary Information on Oil and Gas Operations—Unaudited - Changes in Standardized Measure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure at beginning of year	$ 127,297	$ 67,269	$ 127,685
Sales and transfers of oil and gas produced, net of production costs	(64,148)	(70,362)	(35,993)
Changes in price, net of future production costs	18,542	53,516	(30,427)
Extensions and discoveries, net of future production and development costs	2,983	50,977	864
Changes in estimated future development costs, net of development costs incurred during this period	16,241	17,144	26,356
Revisions of quantity estimates	2,755	(7,482)	(14,889)
Accretion of discount	12,730	6,727	12,769
Purchase of reserves in place	0	549	0
Sale of reserves in place	1,614	(1,305)	(16,701)
Changes in production rates (timing) and other	6,011	10,264	(2,395)
Net increase (decrease) in standardized measure	(3,272)	60,028	(60,416)
Standardized measure at end of year	$ 124,025	$ 127,297	$ 67,269

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Summarized Quarterly Financial Information - Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 19,789	$ 20,886	$ 21,507	$ 24,917	$ 35,080	$ 28,184	$ 24,251	$ 20,772	$ 87,099	$ 108,287	$ 66,667
Loss from operations	701	(3,657)	(1,326)	(821)	221	(1,885)	(2,289)	(3,633)	(5,103)	(7,586)	(90,353)
Loss available to common stockholders	$ (4,117)	$ (4,979)	$ (2,611)	$ (2,212)	$ (389)	$ (3,085)	$ (3,385)	$ (4,918)	$ (13,919)	$ (11,776)	$ (96,245)
Loss per share, Basic (in usd per share)	$ (0.16)	$ (0.19)	$ (0.10)	$ (0.09)	$ (0.02)	$ (0.15)	$ (0.16)	$ (0.23)	$ (0.54)	$ (0.55)	$ (5.24)
Loss per share, Diluted (in usd per share)	$ (0.16)	$ (0.19)	$ (0.10)	$ (0.09)	$ (0.02)	$ (0.15)	$ (0.16)	$ (0.23)	$ (0.54)	$ (0.55)	$ (5.24)