Company Quick10K Filing
Quick10K
Petroquest Energy
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-02-08 Enter Agreement, Leave Agreement, Earnings, Off-BS Arrangement, Sale of Shares, Shareholder Rights, Control, Officers, Amend Bylaw, Other Events, Exhibits
8-K 2019-01-31 Bankruptcy, Exhibits
8-K 2019-01-14 Enter Agreement, Exhibits
8-K 2018-12-18 Enter Agreement, Exhibits
8-K 2018-11-06 Enter Agreement, Bankruptcy, Off-BS Arrangement, Shareholder Rights, Officers, Regulation FD, Other Events, Exhibits
8-K 2018-11-05 Earnings
8-K 2018-10-31 Enter Agreement, Other Events, Exhibits
8-K 2018-10-19 Enter Agreement, Other Events, Exhibits
8-K 2018-10-05 Enter Agreement, Other Events, Exhibits
8-K 2018-09-28 Enter Agreement, Other Events, Exhibits
8-K 2018-09-14 Enter Agreement, Other Events, Exhibits
8-K 2018-08-31 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-08-15 Enter Agreement, Other Events, Exhibits
8-K 2018-08-06 Earnings
8-K 2018-07-31 Other Events
8-K 2018-07-10 Regulation FD, Exhibits
8-K 2018-06-21 Other Events
8-K 2018-05-16 Shareholder Vote, Exhibits
8-K 2018-05-07 Earnings
8-K 2018-04-17 Regulation FD, Exhibits
8-K 2018-03-05 Earnings
8-K 2018-02-20 Regulation FD, Exhibits
8-K 2018-01-31 Enter Agreement, Earnings, Exhibits
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BLGI Black Cactus Global 0
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PQ 2018-12-31
Part I
Item 1 and 2. Business and Properties
Item 1A. Risk Factors
Item 1B Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market Price of and Dividends on Common Stock
Item 6. Selected Financial Data
Item 7.
Item 7A Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Part IV
Item 15. Exhibits, Financial Statement Schedules
Item 16. Form 10-K Summary
Note 1-Organization and Summary of Significant Accounting Policies
Note 2-Voluntary Reorganization Under Chapter 11 of The Bankruptcy Code
Note 3-Acquisitions and Divestitures
Note 4-Equity
Note 5-Earnings per Share
Note 6-Share-Based Compensation
Note 7-Asset Retirement Obligation
Note 8-Derivative Instruments
Note 9 - Fair Value Measurements
Note 10-Long-Term Debt
Note 11-Related Party Transactions
Note 12-Ceiling Test Write-Down
Note 13-Other Comprehensive Income (Loss)
Note 14-Income Taxes
Note 15-Commitments and Contingencies
Note 16-Supplementary Information on Oil and Gas Operations-Unaudited
Note 17 - Summarized Quarterly Financial Information - Unaudited
EX-21.1 exhibit211123118.htm
EX-23.1 exhibit231123118.htm
EX-31.1 exhibit311123118.htm
EX-31.2 exhibit312123118.htm
EX-32.1 exhibit321123118.htm
EX-32.2 exhibit322123118.htm
EX-99.1 exhibit991123118.htm

Petroquest Energy Earnings 2018-12-31

PQ 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 pq12311810k.htm 10-K Document

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
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
 
 
 
PART IV
 
 
 
 
 

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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 decreased 23% 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, 2018 decreased 16% 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, 2018 decreased 16% 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.

#10#



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.

#11#



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


#12#



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.


#13#



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.

#14#



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.

#15#



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.

#16#



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

#17#



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 subject to 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, 2018 decreased 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, 2018 decreased 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, 2018 decreased 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 ended December 31, 2018 decreased 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:
Period                        Redemption 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.
Name                    Age    Position
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, three standing 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