10-K/A 1 yuma_10ka.htm ANNUAL REPORT yuma_10ka.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 10-K /A
(Amendment No.1)

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                        to

Commission File Number: 001-32989

Yuma Energy, Inc.
(Exact name of registrant as specified in its charter)

CALIFORNIA
(State or other jurisdiction of
incorporation or organization)
     
94-0787340
(IRS Employer
Identification No.)

1177 West Loop South, Suite 1825
Houston, Texas
(Address of principal executive offices)
     
 
77027
(Zip Code)

   
(713) 968-7000
(Registrant’s telephone number, including area code)
   

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

Title of each class
     
Name of each exchange on which registered
Common Stock, no par value per share
     
NYSE MKT
9.25% Series A Cumulative Redeemable Preferred Stock
     
NYSE MKT

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. o Yes  x 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. o Yes  x 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. x Yes  o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ý Yes  ¨ No
 
 
 
 
 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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 file, an accelerated file, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated file,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Larger accelerated filer o                                                                                                     Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company)                Smaller reporting company x
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o   No x
 
The aggregate market value on June 30, 2015, (the last business day of the registrant’s most recently completed second fiscal quarter) of the voting shares held by non-affiliates was approximately $14,956,252 based on the closing sales price of the registrant’s common stock on the NYSE MKT on such date.

At March 29, 2016, 71,911,361 shares of the Registrant’s common stock, no par value, were outstanding.


DOCUMENTS INCORPORATED BY REFERENCE

None.
 


 
 
 
 
 
EXPLANATORY NOTE
 
Yuma Energy, Inc. (referred to herein as “Yuma,” the “Company,” “we,” “us” or “our”) is filing this Amendment No. 1 (this “Amended Filing”) to its Annual Report on Form 10-K for the year ended December 31, 2015, originally filed with the Securities and Exchange Commission (“SEC”) on March 30, 2016 (the “Original Filing”), for the purpose of restating previously filed financial statements, including notes thereto, and amending portions of the related disclosures contained in the Original Filing (the “Restatement”). This Amended Filing includes (i) restated consolidated balance sheets as of December 31, 2015 and 2014, (ii) restated consolidated statements of operations, consolidated statements of comprehensive income (loss), consolidated statements of changes in equity and consolidated statements of cash flows for the years ended December 31, 2015, 2014 and 2013 and (iii) restated unaudited quarterly financial information for the quarters ended March 31, 2014 through December 31, 2015. We will not file amended periodic reports for any filing prior to the Original Filing, including Forms 10-Q for any of the affected quarterly periods.
 
Restatement Background
 
On May 11, 2016, subsequent to the filing of our Original Filing, we determined that there were non-cash errors in the computation of our income tax provision and the recording of our deferred taxes related to our asset retirement obligations, our stock based compensation, our allocation of the purchase price in the Pyramid merger and resultant amount of goodwill, the tax amortization of that goodwill, the tax treatment of expenses related to the Pyramid merger, and the incorrect roll forward of the historic net operating losses and the difference in the book and tax basis in our properties. As a result, our income tax provision and the net amount of our deferred tax liability were restated for the years ended December 31, 2015, 2014 and 2013 and the applicable quarterly periods in 2015 and 2014. 

As a result, management, the Audit Committee and the Board of Directors determined after consideration of the relevant facts and circumstances, that our consolidated financial statements as of December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013 contained within the Original Filing, and our financial data included in our interim consolidated financial statements set forth in our quarterly reports on Form 10-Q for the quarter ended September 30, 2014, and for all subsequent quarterly reports on Form 10-Q through the quarter ended December 31, 2015, should be restated, and that such financial statements previously filed with the SEC, should no longer be relied upon. Additionally, it was determined that the Company should, as soon as practicable, file with the SEC an amendment to the Original Filing, inclusive of restated financial data pertaining to each applicable quarterly period in 2015 and 2014.

Management has evaluated the effect of the restatements on its prior conclusions regarding the effectiveness of the Company’s internal control over financial reporting and disclosure controls and procedures as of December 31, 2015 and 2014. In connection therewith, management concluded that the Company did not maintain effective controls over the accuracy and presentation of the accounting for the matters set forth above. The Company identified both the errors and the material weaknesses and has taken action to remediate its procedures and controls. Nevertheless, the Company may continue to report the above material weakness while sufficient testing of newly established procedures and controls occurs.
 
For ease of reference, this Amended Filing amends and restates the Original Filing in its entirety. The following Items have been revised to reflect the impact of the restatement on the affected line items of our consolidated financial statements:
 
●  
Part I, Item 1A – Risk Factors
 
●  
Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
●  
Part II, Item 8 – Financial Statements and Supplementary Data
 
●  
Part II, Item 9A – Controls and Procedures
 
●  
Part IV, Item 15 – Exhibits and Financial Statement Schedules

We have also updated the signature page, the certifications of our Chief Executive Officer and Chief Financial Officer in Exhibits 31.1, 31.2, 32.1 and 32.2, and our audited consolidated financial statements formatted in eXtensible Business Reporting Language (XBRL) in Exhibit 101.
 
Except as provided in this Explanatory Note, or as indicated in the applicable disclosure, this Amended Filing has not been updated to reflect other events occurring after the filing of the Original Filing and does not modify or update information and disclosures in the Original Filing affected by subsequent events. Accordingly, this Amended Filing should be read in conjunction with our filings with the SEC subsequent to the date on which we filed the Original Filing, together with any amendments to those filings.
 
 
 

 
 
TABLE OF CONTENTS


   
Page
 
Glossary of Selected Oil and Natural Gas Terms
1
     
 
PART I
 
Item 1.
Business.
2
Item 1A.
Risk Factors.
21
Item 1B.
Unresolved Staff Comments.
39
Item 2.
Properties.
39
Item 3.
Legal Proceedings.
39
Item 4.
Mine Safety Disclosures.
40
     
 
PART II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
41
Item 6.
Selected Financial Data.
42
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
42
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
56
Item 8.
Financial Statements and Supplementary Data.
57
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures.
57
Item 9A.
Controls and Procedures.
57
Item 9B.
Other Information.
58
     
 
PART III
 
Item 10.
Directors, Executive Officers and Corporate Governance.
59
Item 11.
Executive Compensation.
63
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
70
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
72
Item 14.
Principal Accounting Fees and Services.
73
     
 
PART IV
 
Item 15.
Exhibits, Financial Statement Schedules.
74
 
Signatures.
78


 
 

 
 
Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in this Annual Report on Form 10-K may contain “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 contained in this report are forward-looking statements. These forward-looking statements can generally be identified by the use of words such as “may,” “will,” “could,” “should,” “project,” “intends,” “plans,” “pursue,” “target,” “continue,” “believes,” “anticipates,” “expects,” “estimates,” “predicts,” or “potential,” the negative of such terms or variations thereon, or other comparable terminology. Statements that describe our future plans, strategies, intentions, expectations, objectives, goals or prospects are also forward-looking statements. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under Item 1A. “Risk Factors” of this report and other sections of this report which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

● 
our ability to repay outstanding loans when due;

● 
our limited liquidity and ability to finance our exploration, acquisition and development strategies;

● 
reductions in the borrowing base under our credit facility;

● 
impacts to our financial statements as a result of oil and natural gas property impairment write-downs;

● 
volatility and weakness in commodity prices for oil and natural gas and the effect of prices set or influenced by action of the Organization of the Petroleum Exporting Countries (“OPEC”);

● 
our ability to successfully integrate acquired oil and natural gas businesses and operations;
 
● 
the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and will divert management’s time and energy, which could have an adverse effect on our financial position, results of operations, or cash flows;
 
● 
risks in connection with potential acquisitions and the integration of significant acquisitions;
 
● 
we may incur more debt; higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;
 
● 
our ability to successfully develop our large inventory of undeveloped acreage in our resource plays;
 
● 
our oil and natural gas assets are concentrated in a relatively small number of properties;
 
● 
access to adequate gathering systems, processing facilities, transportation take-away capacity to move our production to market and marketing outlets to sell our production at market prices;
 
● 
our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and seek to develop our undeveloped acreage positions;
 
● 
our ability to replace our oil and natural gas reserves;
 
● 
the presence or recoverability of estimated oil and natural gas reserves and actual future production rates and associated costs;
 
● 
the potential for production decline rates for our wells to be greater than we expect;
 
● 
our ability to retain key members of senior management and key technical employees;
 
● 
environmental risks;
 
 
 

 
 
● 
drilling and operating risks;
 
● 
exploration and development risks;
 
● 
the possibility that our industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulations);
 
● 
general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than we expect, including the possibility that economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;
 
● 
social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as Africa, the Middle East, and armed conflict or acts of terrorism or sabotage;
 
● 
other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;
 
● 
the insurance coverage maintained by us may not adequately cover all losses that may be sustained in connection with our business activities;
 
● 
title to the properties in which we have an interest may be impaired by title defects;
 
● 
management’s ability to execute our plans to meet our goals;
 
● 
the cost and availability of goods and services, such as drilling rigs; and
 
● 
our dependency on the skill, ability and decisions of third party operators of the oil and natural gas properties in which we have a non-operated working interest.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this document. Other than as required under applicable securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.
 
 
 

 

Glossary of Selected Oil and Natural Gas Terms
 
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. As used in this document:

“3-D” means three-dimensional.

“Bbl” or “Bbls” means barrel or barrels of oil or natural gas liquids.

“Bbl/d” means Bbl per day.

“Boe” means barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas.

“Boe/d” means Boe per day.

“Btu” means a British thermal unit, a measure of heating value.

“HH” means Henry Hub natural gas spot price.

“HLS” means Heavy Louisiana Sweet crude spot price.

“LIBOR” means London Interbank Offered Rate.

“LLS” means Argus Light Louisiana Sweet crude spot price.

“LNG” means liquefied natural gas.

“MBbls” means thousand barrels of oil or natural gas liquids.

“MBoe” means thousand Boe.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

“NGL” or “NGLs” means natural gas liquids, which are expressed in barrels.

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

“SEC” means the United States Securities and Exchange Commission.

“U.S.” means the United States of America.

 
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.
 
 
1

 

PART I

Item 1.                                Business.

Overview
 
Unless the context otherwise requires, all references in this report to the “Company,” “Yuma,” “our,” “us,” and “we” refer to Yuma Energy, Inc. (formerly known as Pyramid Oil Company) and its subsidiaries, as a common entity. Unless otherwise noted, all information in this report relating to oil, natural gas and natural gas liquids reserves and the estimated future net cash flows attributable to those reserves are based on estimates prepared by independent reserve engineers and are net to our interest. We have referenced certain technical terms important to an understanding of our business under the Glossary of Selected Oil and Natural Gas Terms section above. Throughout this report we make statements that may be classified as “forward-looking.” Please refer to the Cautionary Statement Regarding Forward-Looking Statements section above for an explanation of these types of statements.

Yuma Energy, Inc. is an independent Houston-based exploration and production company with approximately 13.3 million Boe of proved reserves as of December 31, 2015.  We are focused on the acquisition, development, and exploration for conventional and unconventional oil and natural gas resources, primarily in the U.S. Gulf Coast and California. We were incorporated in California on October 7, 1909. We have employed a 3-D seismic-based strategy to build a multi-year inventory of development and exploration prospects. Our current operations are focused on onshore assets located in central and southern Louisiana, where we are targeting the Austin Chalk, Tuscaloosa, Wilcox, Frio, Marg Tex and Hackberry formations. In addition, we have a non-operated position in the Bakken Shale in North Dakota and operated positions in Kern and Santa Barbara Counties in California. Our common stock is traded on the NYSE MKT under the trading symbol “YUMA.” Our Series A Preferred Stock is traded on the NYSE MKT under the trading symbol “YUMAprA.”

Recent Developments

Agreement and Plan of Merger and Reorganization

On February 10, 2016, the Company and privately held Davis Petroleum Acquisition Corp. (“Davis”) entered into a definitive merger agreement for an all-stock transaction. Upon completion of the transaction, we will reincorporate in Delaware, implement a one-for-ten reverse split of our common stock, and convert each share of our existing Series A Preferred Stock into 35 shares of common stock prior to giving effect for the reverse split (3.5 shares post reverse split).  Following these actions, we will issue additional shares of common stock in an amount sufficient to result in approximately 61.1% of the common stock being owned by the current common stockholders of Davis.  In addition, we will issue approximately 3.3 million shares of a new Series D preferred stock to existing Davis preferred stockholders, which  is estimated to have a conversion price of approximately $5.70 per share, after giving effect for the reverse split.  The Series D preferred stock is estimated to have an aggregate liquidation preference of approximately $19.0 million at closing, and will be paid dividends in the form of additional shares of Series D preferred stock at a rate of 7% per annum. Upon closing, there will be an aggregate of approximately 23.7 million shares of our common stock outstanding (after giving effect to the reverse stock split and conversion of Series A Preferred Stock to common stock). The transaction is expected to qualify as a tax-deferred reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended (the “Code”).
 
The merger agreement is subject to the approval of the shareholders of both companies, as well as other customary approvals, including authorization to list the newly issued shares on the NYSE MKT. The parties anticipate completing the transaction in mid-2016.
 
Davis is a Houston-based oil and gas company focused on the acquisition, exploration and development of domestic oil and gas properties.  Over 90% of the common stock of Davis is owned by entities controlled by or co-investing with Evercore Capital Partners, Red Mountain Capital Partners, and Sankaty Advisors. These major stockholders purchased the predecessor company from the family of Marvin Davis in 2006.  Davis’ company-operated properties are conventional fields located onshore in south Louisiana and the upper Texas Gulf Coast, and its non-operated properties include Eagle Ford and Woodbine properties in east Texas.
 
 
2

 

Upon closing, four of the five current Yuma Board members will continue to serve on the combined company Board.  Richard K. Stoneburner will serve as Non-Executive Chairman, and Sam L. Banks will continue to serve as Director, President and Chief Executive Officer.  James W. Christmas and Frank A. Lodzinski will also continue to serve.  Three additional Directors will be nominated by Davis, bringing the size of the new Board to seven, and the Board will meet the director independence requirements of the NYSE MKT.  All current officers of Yuma will serve in their same capacity in the combined company.

Amendment to Senior Credit Agreement

On December 30, 2015, we entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment (the “Amendment”) to our Credit Agreement (the “credit agreement”) with Société Générale (the “Bank”) as administrative agent and issuing bank, and each of the lenders and guarantors party thereto. Pursuant to the Amendment, the borrowing base under the credit agreement was reduced from $35.0 million to $29.8 million and will automatically be reduced to $20.0 million on May 31, 2016 unless otherwise reduced by or to a different amount by the lenders under the credit agreement. The Amendment also provided a waiver of the financial covenant related to the maximum permitted ratio of funded debt to EBITDA for the fiscal quarter ended September 30, 2015 and any failure to comply with that financial covenant and certain other financial covenants for the fiscal quarter ended December 31, 2015. Pursuant to the Amendment, we agreed that on or before February 6, 2016, we will engage an investment bank to explore strategic options for our finances and, on or before March 31, 2016, we will either enter into an underwritten commitment for additional capital in an aggregate amount sufficient for us to pay any borrowing base deficiency then existing or enter into a definitive agreement for the acquisition by a third party of all or substantially all of our assets by merger, asset purchase, equity purchase or other structure acceptable to the Bank and the lenders. Thereafter, on February 10, 2016, we entered into the merger agreement with Davis as discussed above, and we expect to enter into another amendment to the credit agreement to account for the contemplated merger with Davis.

In addition, the Amendment to the credit agreement provides for a line of credit until May 20, 2017. Pursuant to the credit agreement, we secured a credit facility (the “credit facility”), which is available to provide financing of up to $29.8 million through May 31, 2016 and thereafter the borrowing base will automatically be reduced to $20.0 million unless otherwise reduced by or to a different amount by the lenders under the credit agreement. The credit agreement is secured by a first lien on substantially all of our assets. As of March 29, 2016, the borrowing base was $29.8 million and the debt outstanding was $29.8 million. Amounts borrowed under the credit agreement bear interest at either (a) LIBOR plus 2.25% to 3.25% or (b) the prime rate plus 1.25% to 2.25%, depending on the amount borrowed under the credit facility. The credit facility contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness, create liens on assets, sell certain assets and engage in certain transactions with affiliates. Additionally, the credit agreement contains a covenant restricting the payment of dividends on our preferred stock if there is less than ten percent availability on the borrowing base. The credit facility also requires the maintenance of certain financial ratios. For the fiscal quarters ended September 30, 2015 and December 31, 2015, we were not in compliance with certain financial ratio covenants in the credit agreement; however, we received a waiver from the lenders under the credit agreement pursuant to the Amendment. See Part II, Item 8. Notes to the Consolidated Financial Statements, Note 3 – Liquidity Considerations and Note 13 – Debt and Interest Expense.

Issuance of 9.25% Series A Cumulative Redeemable Preferred Stock

In October 2014, we closed a public offering of 507,739 shares of our 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share, with a liquidation preference of $25.00 per share (the “Series A Preferred Stock”), at a public offering price of $22.00 per share, with aggregate net proceeds of $10,430,894, net of the underwriters’ discount and underwriters’ expenses. During the year ended December 31, 2015, we sold 46,857 shares of Series A Preferred Stock with aggregate net proceeds of $870,386, net of underwriters’ discount and underwriters’ expenses under an At-the-Market Issuance Sales Agreement (see below).

At-the-Market Issuance Sales Agreement

On December 19, 2014, we entered into an At-the-Market Issuance Sales Agreement (the “sales agreement”) with an investment banking firm (the “Agent”). Under this sales agreement, we could issue and sell shares of our Series A Preferred Stock and shares of our common stock. The offer and sale of these shares was registered under a shelf registration statement filed with the SEC on November 21, 2013. The sales agreement provides that our Series A Preferred Stock and our common stock will be sold at market prices prevailing at the time of the sale of such shares, at no discount to market. We were not obligated to make any sales under the sales agreement. We have agreed to pay the Agent a commission rate of up to 6.0% of the gross proceeds from the sale of shares of Series A Preferred Stock and shares of our common stock sold through the Agent under the sales agreement, reimburse the Agent for certain expenses incurred in connection with entering into the sales agreement, and provide the Agent with customary indemnification rights. The full terms and text of the sales agreement were filed with our Current Report on Form 8-K on December 29, 2014. During the year ended December 31, 2015, we sold 46,857 shares of Series A Preferred Stock and 1,347,458 shares of our common stock under the sales agreement.
 
 
3

 

Operating Outlook

During 2015, the oil and natural gas industry experienced significant decreases in commodity prices driven by supply and demand imbalances for oil internationally and for natural gas in the United States.  The decline in commodity prices and global economic conditions have continued into 2016, and low commodity prices may exist for an extended period of time.

We plan to continue our disciplined approach in 2016 by emphasizing liquidity and value over growth, enhancing operational efficiencies, and reducing capital expenses.  We will continue to evaluate the oil and natural gas price environments and may adjust our capital spending plans, capital raising activities, and strategic alternatives (including possible asset sales) to maintain appropriate liquidity and financial flexibility.

Business Strategy
 
Our business strategy is to achieve long-term growth in production and cash flow on a cost-effective basis. We focus on maximizing our return on capital employed and adding production and reserves through acquisitions, mergers, exploration and the development of our Austin Chalk, Tuscaloosa, Wilcox, Frio, Marg Tex, Hackberry, Bakken, Three Forks, and Monterey Shale acreage.
 
The key elements of our business strategy are:

» 
seek merger and acquisition opportunities to increase the Company’s liquidity, as well as reduce G&A on a per Boe basis to the Company;

» 
transition existing inventory of reserves into oil and natural gas production;

» 
add selectively to project inventory through ongoing prospect generation, exploration and strategic acquisitions; and

» 
retain a greater percentage working interest in, and operatorship of, our projects going forward.

  » 
Our core competencies include oil and natural gas operating activities and expertise in generating:

» 
unconventional oil resource plays;

» 
onshore liquids-rich prospects through the use of 3-D seismic surveys; and

» 
identification of high impact deep onshore prospects located beneath known producing trends through the use of 3-D seismic surveys.

Our Key Strengths and Competitive Advantages

We believe the following are our key strengths and competitive advantages:

» 
Extensive technical knowledge and history of operations in the Gulf Coast region. Since 1983 Yuma Co. or its predecessor has operated in the Gulf Coast region, which is an area that extends through Texas, Louisiana and Mississippi. We believe our extensive understanding of the geology and experience in interpreting well control, core and 3-D seismic data in this area provides us with a competitive advantage in exploring and developing projects in the Gulf Coast region. We have cultivated amicable and mutually beneficial relationships with acreage owners in this region and adjacent oil and natural gas operators, which generally provides for effective leasing and development activities.
 
 
4

 
 
» 
In-house technical expertise in 3-D seismic programs. We design and generate in-house 3-D seismic survey programs on many of our projects. By controlling the 3-D seismic program from field acquisition through seismic processing and interpretation, we gain a competitive advantage through proprietary knowledge of the project.

» 
Liquids-rich, quality assets with attractive economics. Our assets and potential future drilling locations are primarily in oil plays with associated liquids-rich natural gas.

» 
Diversified portfolio of producing and non-producing assets. Our current portfolio of producing and non-producing assets covers a large area within the Gulf Coast, the Bakken/Three Forks shale in North Dakota, and the Monterey Shale, along with shallow oil fields in central and southern California.

» 
Significant inventory of oil and natural gas assets. We have an inventory of both proved reserves and significant growth assets that we believe can be developed over the near to medium term. In addition, we have the ability to organically generate new oil and natural gas prospects and projects through techniques utilized by our experienced management team, which include analyzing subsurface data, negotiating mineral rights with landowners in prospective areas, and shooting and reprocessing 3-D seismic surveys.

» 
Company operated assets. In order to maintain better control over our assets, we have established a leasehold position comprised primarily of assets where we are the operator. By controlling operations, we are able to dictate the pace of development and better manage the cost, type, and timing of exploration and development activities.

» 
Experienced management team. We have a highly qualified management team with many years of industry experience, including extensive experience in the Gulf Coast region. Our team has substantial expertise in the design, acquisition, processing and interpretation of 3-D seismic surveys, and our experienced operations staff allows for efficient turnaround from project identification, to drilling, to production.

» 
Experienced board of directors. Our directors have substantial experience managing successful public companies and realizing value for investors through the development, acquisition and monetization of both conventional and unconventional oil and natural gas assets in the Gulf Coast region.

Description of Major Properties

We are the operator of properties containing approximately 78% of our proved oil and natural gas reserves as of December 31, 2015. As operator, we are able to directly influence exploration, development and production operations. Our producing properties have reasonably predictable production profiles and cash flows, subject to commodity price fluctuations, and have provided a foundation for our technical staff to pursue the development of our undeveloped acreage, further develop our existing properties and also generate new projects that we believe have the potential to increase shareholder value.

As is common in the industry, we participate in non-operated properties on a selective basis; our non-operating participation decisions are dependent on the technical and economic nature of the projects and the operating expertise and financial standing of the operators. The following is a description of our significant oil and natural gas properties.
 
 
5

 

Greater Masters Creek Field Area, Allen, Vernon, Rapides and Beauregard Parishes, Louisiana. Our Greater Masters Creek Field properties are located in the Austin Chalk Trend in west central Louisiana. At December 31, 2015, we held approximately 61,986 net acres in the field.  The acreage is located within an existing field which has previously been partially developed. Based on our technical analysis and independent third-party engineering, we believe we hold interest in approximately 22 operated proved undeveloped locations, three non-operated proved undeveloped locations, 63 operated non-proved undeveloped locations, and 11 non-operated non-proved undeveloped locations that are either held by production or contain existing leasehold. We are currently seeking joint venture partners to participate in the future drilling and development of these locations, which would reduce our participating interest in these locations and thereby reduce our future capital expenditures and associated proved and non-proved reserves and production. We plan to drill one proved undeveloped well this year and the remaining proved undeveloped wells within five years from the date they were originally recorded.

During the first quarter of 2016, we shut-in 14 Austin Chalk wells in Beauregard, Rapides and Vernon Parishes, Louisiana due to low oil and natural gas prices. If we do not restart production from these wells, the associated leases will expire reducing our proved reserves by approximately 1,629 MBoe, our acreage by 22,021 gross (18,140 net) acres, our operated proved undeveloped locations by three, and our operated non-proved undeveloped locations by seven.

During the first quarter of 2016, we received notice from the operator of certain wells in Rapides and Vernon Parishes, Louisiana, that certain wells in which we have an interest were shut-in due to current economic conditions.  The operator plans to sell its interest.  If the operator does not restart production from these wells or if a subsequent operator does not restart production from these wells, the associated leases will expire, which would reduce our proved reserves by approximately 285 MBoe, our acreage by 18,895 gross (3,737 net) acres, our non-operated proved undeveloped locations by three, and our non-operated non-proved undeveloped locations by 18.

We are currently negotiating with a certain mineral owner to amend the oil and gas lease agreement to extend the expiration date of certain acreage that is not held by production as of March 29, 2016.  The total acreage is approximately 25,139 acres which will expire July 1, 2016 unless we initiate drilling of a development well on the pooled lands or pay a deferred development payment by July 1, 2016.  If the leased acreage expires, our proved reserves would be reduced by approximately 5,096 MBoe, the number of operated proved undeveloped locations and operated non-proved locations would be reduced by 13 and 16, respectively.

This field is highly material to our future results of operations and financial position. For further information on this development project, see Item 1A. “Risk Factors.”

La Posada – Bayou Hebert Field, Vermilion Parish, Louisiana. We have a 12.5% non-operated working interest in La Posada (Bayou Hebert) Field which is comprised of three wells producing from the Lower Planulina Cris R sands, and approximately 1,600 gross acres (200 net acres). In 2016, the operator may recomplete one or more wells to up-hole Cris R zones.  The field averaged approximately 50.1 MMcf/d of natural gas and 950 Bbl/d of oil gross (4.5 MMcf/d and 85 Bbl/d net) during the month of December 2015.

Livingston – Beaver Dam Creek Field, Bills Branch Field, Livingston North Field, St. Helena and Livingston Parishes, Louisiana. We operate four wells producing oil from the lower Tuscaloosa sands, three wells producing from the Wilcox sands, and one salt water disposal well.  We hold an average working interest of 39% in these wells.  2015 operational activities focused on increasing oil production and profitability by installing and optimizing artificial lift systems and reducing operating costs.  The average daily production from the seven producing wells during December 2015 was approximately 558 Bbl/d of oil gross (156 Bbl/d net).

Lake Fortuna Field (Raccoon Island), St. Bernard Parish, Louisiana. We discovered our Lake Fortuna field in 1996 when our 3-D Raccoon Island prospect was drilled. The target was a Middle Miocene sand on a known productive structure. In 2005, we acquired the majority of the working interest in Raccoon Island from Amerada Hess, and now own a working interest of 91%.  Throughout December 2015, production levels in the field averaged approximately 118 Bbl/d of oil gross (77 Bbl/d net).

Gardner Island and Branville Bay, St. Bernard Parish, Louisiana.  We hold an average working interest of 36% in 1,344 gross acres (484 net acres). Throughout December 2015, production levels in the field averaged approximately 359 Bbl/d of oil gross (97 Bbl/d net).
 
 
6

 

Kern County Field Area, Kern County, California. We hold 100% working interest in 960 gross lease acres and 244 fee acres in Kern County, California. We operate seven fields producing from Pliocene, Miocene, Oligocene, and Eocene age reservoirs from relatively shallow depths.  These assets are characterized by long-life shallow decline production.  For the month ended December 31, 2015, production totaled 145 Bbls of oil per day gross (123 Bbl/d net).

Livingston 3-D Project, St. Helena and Livingston Parishes, Louisiana. In 2009 and 2010, we shot a 138 square mile 3-D seismic survey targeting the intermediate depth Wilcox sands at approximately 10,000 feet deep and the deeper lower Tuscaloosa sands at approximately 15,000 feet. We hold an average working interest of 39% across 3,292 gross (1,973 net) lease option acres in the Livingston 3-D Project area and we are the operator and have access rights to drill additional exploration wells to both the Lower Tuscaloosa and the Wilcox oil sands, the future drilling of which are dependent on economic conditions.

Amazon 3-D Project, Calcasieu and Jefferson Parishes, Louisiana. In 2011, we shot a 70 square mile 3-D seismic survey targeting the Frio (Hackberry and Marg Tex/Cib Haz/Camerina objectives). The Hackberry is a “bright spot” play for natural gas with rich condensate yields found in stratigraphic traps at depths of approximately 13,000 feet. The Marg Tex/Cib Haz/Camerina objectives are found at depths typically around 9,000 feet in structural traps independent of the underlying Hackberry. We do not plan to drill any new wells in the Amazon 3-D Project in 2016.

Cat Canyon Field, Santa Barbara County, California. Our Cat Canyon field is a legacy asset that was developed and owned by Pyramid Oil Company prior to our merger completed on September 10, 2014.  The field has produced from the Monterey formation at a depth of 4,500 feet and is nearly 2,000 feet thick.  We have a 100% working interest in 149 acres in this field. The field is surrounded by Monterey wells drilled from the late 1940’s through 1982 on 10 acre spacing. The wells are drilled vertically, completed naturally (without fracking) and are put on pump immediately. We plan to drill our first operated well on this property in 2016.

Bakken – Yellowstone and Southeast Homerun, McKenzie County, North Dakota. At December 31, 2015, we held an average 4.6% non-operated working interest in 18,553 gross acres (674 net acres) in McKenzie County, North Dakota. We have interests in six producing oil wells and two active salt water disposal wells. All producing wells are located in two fields, Yellowstone and Southeast Homerun. The majority of our interests are currently operated by Zavanna, LLC. For the month ended December 31, 2015, gross production totaled 427 Boe per day (14 Boe/d net). We currently estimate that significant future infill Bakken and Three Forks development upside potential exists on our acreage, the development of which will be influenced largely by future oil and natural gas commodities prices.

Oil and Natural Gas Reserves

All of our oil and natural gas reserves are located in the United States. Unaudited information concerning the estimated net quantities of all of our proved reserves and the standardized measure of future net cash flows from the reserves is presented in Note 25 – Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited) in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this report. The reserve estimates have been prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. We have no long-term supply or similar agreements with foreign governments or authorities. We did not provide any reserve information to any federal agencies in 2015 other than to the SEC.

Estimated Proved Reserves

The table below summarizes our estimated proved reserves at December 31, 2015 based on reports prepared by NSAI. In preparing these reports, NSAI evaluated 100% of our properties at December 31, 2015. For more information regarding our independent reserve engineers, please see Independent Reserve Engineers below. The information in the following table does not give any effect to or reflect our commodity derivatives.
 
 
7

 

   
Oil
(MBbls)
   
Natural Gas Liquids
(MBbls)
   
Natural Gas
(MMcf)
   
Total
(MBoe)(1)
   
Present Value Discounted at 10%
($ in thousands)(2)
 
Proved developed (3)
                             
Greater Masters Creek Field (4)
    204       26       269       275     $ (792 )
La Posada (Bayou Hebert) Field (4)
    129       221       5,735       1,305     $ 17,589  
Other
    1,469       69       2,549       1,963     $ 27,275  
Total proved developed
    1,802       316       8,553       3,543     $ 44,072  
Proved undeveloped (3)
                                       
Greater Masters Creek Field (4)
    4,398       1,585       13,164       8,177     $ 65,967  
La Posada (Bayou Hebert) Field (4)
    76       150       3,898       876     $ 6,881  
Other
    640       0       155       665     $ 5,988  
Total proved undeveloped
    5,114       1,735       17,217       9,718     $ 78,836  
Total proved (3)
    6,916       2,051       25,770       13,261     $ 122,908  
 
(1)           Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).

(2)           Present Value Discounted at 10% (“PV10”) is a Non-GAAP measure that differs from the GAAP measure “standardized measure of discounted future net cash flows” in that PV10 is calculated without regard to future income taxes. Management believes that the presentation of the PV10 value is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe the use of a pre-tax measure provides greater comparability of assets when evaluating companies. For these reasons, management uses, and believes the industry generally uses, the PV10 measure in evaluating and comparing acquisition candidates and assessing the potential return on investment related to investments in oil and natural gas properties. PV10 includes estimated abandonment costs less salvage.  PV10 does not necessarily represent the fair market value of oil and natural gas properties.
 
PV10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. For a presentation of the standardized measure of discounted future net cash flows, see Note 25 – Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited) in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this report. The table below titled “Non-GAAP Reconciliation” provides a reconciliation of PV10 to the standardized measure of discounted future net cash flows.

Non-GAAP Reconciliation ($ in thousands)
 
The following table reconciles our direct interest in oil, natural gas and natural gas liquids reserves as of December 31, 2015:

    (As Restated)  
Present value of estimated future net revenues (PV10)
  $ 122,908  
Future income taxes discounted at 10%
    (16,363 )
Standardized measure of discounted future net cash flows
  $ 106,545  

(3)           Proved reserves were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month prices for each of the preceding twelve months, which were $50.28 per Bbl (WTI) and $2.59 per MMBtu (HH), for the year ended December 31, 2015. Adjustments were made for location and grade.

(4)           Our Greater Masters Creek Field and La Posada (Bayou Hebert) field were our only fields that each contained 15% or more of our estimated proved reserves as of December 31, 2015.

We have stress-tested our proved reserve estimates as of December 31, 2015 to determine the impact of lower crude oil and natural gas prices. Replacing the twelve-month unweighted arithmetic average commodity prices used in estimating our reported proved reserves (see Note 25 – Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited) in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this report) with those shown on the table below, and leaving all other parameters unchanged, results in a decrease in our estimated proved reserves as shown below.
 
 
8

 
 
   
Pricing Scenario
             
   
Crude Oil (per Bbl) (1)
   
Natural Gas (per MMBtu) (1)
   
Proved Reserves (MBoe)
   
% Change from December 31, 2015 Estimated Reserves
 
2015 Reserve Report (2)
  $ 50.28     $ 2.59       13,261       -  
                                 
Scenario A
  $ 40.00     $ 2.25       12,876       (3 %)
                                 
Scenario B
  $ 30.00     $ 2.00       9,358       (29 %)

(1)  
These prices are indices and do not include basin differentials for crude oil and natural gas. The above scenarios were calculated using the indicated index prices, less any basin differentials, transport fees, contractual adjustments and any Btu adjustments we experienced for the respective commodity.

(2)  
The NYMEX prices used for our 2015 year-end independent engineering reserve report are based on SEC price parameters using the twelve-month unweighted arithmetic average of the first-day-of-the-month prices for each of the preceding twelve months for the year ended December 31, 2015.

Proved Undeveloped Reserves

At December 31, 2015, our estimated proved undeveloped (“PUD”) reserves were approximately 9,718 MBoe. The following table details the changes in PUD reserves for the year ended December 31, 2015 (in MBoe):

Beginning proved undeveloped reserves at January 1, 2015
    16,243  
Undeveloped reserves transferred to developed
    (100 )
Purchases of minerals-in-place
    43  
Extensions and discoveries
    459  
Production
    0  
Revisions
    (6,927 )
Proved undeveloped reserves at December 31, 2015
    9,718  

From January 1, 2015 to December 31, 2015, our PUD reserves decreased 40.2% from 16,243 MBoe to 9,718 MBoe, or a decrease of 6,525 MBoe. Reserves of 100 MBoe were moved from the PUD reserve category to the proved developed producing category through the drilling of the Talbot 23-1 well. We incurred approximately $3.2 million in capital expenditures during the year ended December 31, 2015 in converting this well to the proved developed reserve category. We acquired 43 MBoe through purchases of minerals-in-place and added 459 MBoe through extensions of existing discoveries.  The remaining change to our year-end 2015 PUDs of 6,927 MBoe was a result of downward revisions due to price of 4,293 MBoe, upward performance revisions of 1,829 MBoe, and downward revision due to reclassifying 4,463 MBoe of Greater Masters Creek Field Area undeveloped reserves to non-proved due to the depressed price environment and expected effect on the Company’s access to capital and drilling plans.  As of December 31, 2015, we plan to drill all of our PUD drilling locations within five years from the date they were initially recorded.

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control.  Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of the estimates, as well as economic factors such as change in product prices, may require revision of such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates.

Technology Used to Establish Reserves

Under SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
 
 
9

 

To establish reasonable certainty with respect to our estimated proved reserves, NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using both volumetric estimates and performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Independent Reserve Engineers

We engaged NSAI to prepare our annual reserve estimates and have relied on NSAI’s expertise to ensure that our reserve estimates are prepared in compliance with SEC guidelines. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are G. Lance Binder and Philip R. Hodgson. Mr. Binder has been practicing consulting petroleum engineering at NSAI since 1983. Mr. Binder is a Registered Professional Engineer in the State of Texas (No. 61794) and has over 30 years of practical experience in petroleum engineering, with over 30 years of experience in the estimation and evaluation of reserves. He graduated from Purdue University in 1978 with a Bachelor of Science degree in Chemical Engineering. Mr. Hodgson has been practicing consulting petroleum geology at NSAI since 1998. Mr. Hodgson is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1314) and has over 30 years of practical experience in petroleum geosciences. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our Executive Vice President and Chief Operating Officer is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for overseeing the independent petroleum engineering firm during the preparation of our reserve report. He has a Bachelor of Science degree in Petroleum Engineering and over 30 years of industry experience, with 20 years or more of experience working as a reservoir engineer, reservoir engineering manager, or reservoir engineering executive.  His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. The Executive Vice President and Chief Operating Officer reports directly to our Chief Executive Officer.

Internal Control over Preparation of Reserve Estimates

We maintain adequate and effective internal controls over our reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial data, ownership interest, and production data. The relevant field and reservoir technical information, which is updated annually, is assessed for validity when our independent petroleum engineering firm has technical meetings with our engineers, geologists, and operations and land personnel. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. All current financial data such as commodity prices, lease operating expenses, production taxes and field-level commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also subject to our internal controls over financial reporting, and they are incorporated in our reserve database as well and verified internally by us to ensure their accuracy and completeness. Once the reserve database has been updated with current information, and the relevant technical support material has been assembled, our independent engineering firm meets with our technical personnel to review field performance and future development plans in order to further verify the validity of estimates. Following these reviews the reserve database is furnished to NSAI so that it can prepare its independent reserve estimates and final report. The reserve estimates prepared by NSAI are reviewed and compared to our internal estimates by our Chief Operating Officer and our reservoir engineering staff. Material reserve estimation differences are reviewed between NSAI’s reserve estimates and our internally prepared reserves on a case-by-case basis. An iterative process is performed between NSAI and us, and additional data is provided to address any differences. If the supporting documentation will not justify additional changes, the NSAI reserves are accepted. In the event that additional data supports a reserve estimation adjustment, NSAI will analyze the additional data, and may make changes it deems necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed and all material differences are reconciled, the reserve report is finalized and our reserve database is updated with the final estimates provided by NSAI. Access to our reserve database is restricted to specific members of our reservoir engineering department and management.
 
 
10

 

Production, Average Price and Average Production Cost

The net quantities of oil, natural gas and natural gas liquids produced and sold by us for each of the years ended December 31, 2015, 2014 and 2013, the average sales price per unit sold and the average production cost per unit are presented below.
 
   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
Production volumes:
                 
Crude oil and condensate (Bbls)
    247,177       231,816       184,349  
Natural gas (Mcf)
    1,993,842       2,714,586       1,580,468  
Natural gas liquids (Bbls)
    74,511       97,783       51,875  
Total (Boe) (1)
    653,995       782,030       499,635  
Average prices realized:
                       
Excluding commodity derivatives:
                       
   Crude oil and condensate (per Bbl)
  $ 48.07     $ 93.98     $ 104.26  
   Natural gas (per Mcf)
  $ 2.60     $ 4.62     $ 3.83  
   Natural gas liquids (per Bbl)
  $ 18.89     $ 38.44     $ 40.17  
Including commodity derivatives:
                       
   Crude oil and condensate (per Bbl)
  $ 65.20     $ 101.98     $ 104.39  
   Natural gas (per Mcf)
  $ 3.00     $ 5.19     $ 3.71  
   Natural gas liquids (per Bbl)
  $ 18.89     $ 38.44     $ 40.17  
Production cost per Boe (2)
  $ 13.22     $ 11.60     $ 12.40  

 
(1)
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).

 
(2)
Excludes ad valorem taxes (which are included in lease operating expenses on our Consolidated Statements of Operations in the Consolidated Financial Statements in Part II, Item 8 in this report) and severance taxes, totaling $2,758,207, $3,741,513, and $3,121,185 in fiscal years 2015, 2014 and 2013, respectively.

Effective January 1, 2013, we acquired our interest in the Greater Masters Creek Field Area, which contained 64%, 79% and 78% of our total proved reserves as of December 31, 2015, 2014 and 2013, respectively. Our interests in La Posada (Bayou Hebert) field represented 16% of our total proved reserves as of December 31, 2015. No other single field accounted for 15% or more of our proved reserves as of December 31, 2015, 2014 and 2013. The net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 31, 2015, 2014 and 2013, the average sales price per unit sold and the average production cost per unit for the Greater Masters Creek Field Area are presented below.
 
 
11

 
 
   
Years Ended December 31,
 
Greater Masters Creek Field Area
 
2015
   
2014
   
2013
 
Production volumes:
                 
Crude oil and condensate (Bbls)
    27,379       45,656       24,972  
Natural gas (Mcf)
    102,309       170,916       85,866  
Natural gas liquids (Bbls)
    8,192       16,558       8,702  
Total (Boe) (1)
    52,623       90,700       47,985  
Average prices realized: (2)
                       
   Crude oil and condensate (per Bbl)
  $ 47.29     $ 95.29     $ 100.87  
   Natural gas (per Mcf)
  $ 2.59     $ 4.68     $ 4.07  
   Natural gas liquids (per Bbl)
  $ 15.21     $ 33.67     $ 34.98  
Production cost per Boe (3)
  $ 48.39     $ 43.10     $ 55.89  

 
(1)
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).
 
(2)
Excludes commodity derivatives as they are not recorded by specific field.
 
(3)
Excludes ad valorem taxes (which are included in lease operating expenses on our Consolidated Statements of Operations in the Consolidated Financial Statements in Part II, Item 8 in this report) and severance taxes, totaling $934,131, $1,111,162, and $875,488 in fiscal years 2015, 2014 and 2013, respectively.

The net quantities of oil, natural gas and natural gas liquids produced and sold by us for the year ended December 31, 2015, the average sales price per unit sold and the average production cost per unit for our La Posada (Bayou Hebert) field are presented below.
 
La Posada (Bayou Hebert) Field
 
Year Ended December 31, 2015
 
Production volumes:
     
Crude oil and condensate (Bbls)
    32,950  
Natural gas (Mcf)
    1,645,202  
Natural gas liquids (Bbls)
    58,913  
Total (Boe) (1)
    366,063  
Average prices realized: (2)
       
   Crude oil and condensate (per Bbl)
  $ 49.40  
   Natural gas (per Mcf)
  $ 2.62  
   Natural gas liquids (per Bbl)
  $ 19.99  
Production cost per Boe (3)
  $ 3.91  

 
(1)
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).
 
(2)
Excludes commodity derivatives as they are not recorded by specific field.
 
(3)
Excludes severance taxes but includes ad valorem taxes in lease operating expenses since this well is non-operated by us and the operator does not break out the ad valorem taxes from lease operating expenses.

Gross and Net Productive Wells

As of December 31, 2015, our total gross and net productive wells were as follows:

Oil (1)
   
Natural Gas (1)
   
Total (1)
 
Gross
Wells
   
Net
Wells
   
Gross
Wells
   
Net
Wells
   
Gross
Wells
   
Net
Wells
 
  130       90       47       3       177       93  
 
 
(1)
A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractions of working interests we own in gross wells. Productive wells are producing wells plus shut-in wells we deem capable of production. Horizontal re-entries of existing wells do not increase a well total above one gross well. We have working interests in 10 gross wells with completions into more than one productive zone; in the table above, these wells with multiple completions are only counted as one gross well.
 
 
12

 
 
Gross and Net Developed and Undeveloped Acres

As of December 31, 2015, we had total gross and net developed and undeveloped leasehold acres as set forth below. The developed acreage is stated on the basis of spacing units designated or permitted by state regulatory authorities. Gross acres are those acres in which a working interest is owned. The number of net acres represents the sum of fractional working interests we own in gross acres.

   
Developed
   
Undeveloped
   
Total
 
State
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Louisiana
    77,589       33,962       32,459       31,899       110,048       65,861  
North Dakota
    18,553       674       -       -       18,553       674  
Texas
    1,036       72       80       68       1,116       140  
Oklahoma
    2,160       96       -       -       2,160       96  
California
    1,422       1,400       -       -       1,422       1,400  
Wyoming
    7,360       3       -       -       7,360       3  
Total
    108,120       36,207       32,539       31,967       140,659       68,174  

As of December 31, 2015, we had leases representing 24,377 net acres (24,141 of which were in the Greater Masters Creek Field Area) expiring in 2016; 7,514 net acres (6,219 of which were in the Greater Masters Creek Field Area) expiring in 2017; and 76 net acres (10 of which were in the Greater Masters Creek Field Area) expiring in 2018 and beyond. We believe that our current and future drilling plans, along with selected lease extensions, can address the majority of the leases expiring in the Greater Masters Creek Field Area and our other fields in 2016 and beyond. As disclosed earlier in this report, during the first quarter of 2016, we received notice from the operator of certain Greater Masters Creek Field Area wells that they had shut-in certain wells in which we have an interest due to current economic conditions.  If production is not restarted from these wells, the associated leases will expire, which would reduce our acreage by 18,895 gross (3,737 net) acres.  Additionally, during the first quarter of 2016, we shut-in 14 Greater Masters Creek Field Area wells due to low oil and natural gas prices. If we do not restart production from these wells, the associated leases will expire reducing our acreage by 22,021 gross (18,140 net) acres.  Finally, we are currently negotiating with a certain mineral owner to amend the oil and gas lease agreement to extend the expiration date of certain acreage that, as of March 29, 2016, was not held by production.  The total acreage is approximately 25,139 net acres which will expire July 1, 2016 unless we initiate drilling of a development well on the pooled lands or pay a deferred development payment by July 1, 2016.

Exploratory Wells and Development Wells

Set forth below for the years ended December 31, 2015, 2014 and 2013 is information concerning our drilling activity during the years indicated.

   
Net Exploratory
Wells Drilled
   
Net Development
Wells Drilled
   
Total Net Productive
and Dry Wells
 
Year
 
Productive
   
Dry
   
Productive
   
Dry
   
Drilled
 
2015
    -       -       .51       -       .51  
2014
    .61       -       .54       -       1.15  
2013
    .32       -       .57       .31       1.20  

Present Activities

At March 29, 2016, we had 0 gross (0 net) wells in the process of drilling or completing.

Supply Contracts or Agreements

Crude oil and condensate are sold through month-to-month evergreen contracts.  The price is tied to an index or a weighted monthly average of posted prices with certain adjustments for gravity, Basic Sediment and Water (“BS&W”) and transportation.  Generally, the index or posting is based on West Texas Intermediate (“WTI”) and adjusted to Light Louisiana Sweet (“LLS”) or Heavy Louisiana Sweet (“HLS”).  For the years ended December 31, 2015, 2014 and 2013, the LLS postings averaged $3.48, $3.02, and $9.58 over WTI, respectively.  Pricing for our California properties is based on an average of specified posted prices, adjusted for gravity, transportation, and for one field, a market differential.
 
 
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Our natural gas is sold under multi-year contracts with pricing tied to either first of the month index or a monthly weighted average of purchaser prices received.  Natural gas liquids are also sold under multi-year contacts usually tied to the related natural gas contract.  Pricing is based on published prices for each product or a monthly weighted average of purchaser prices received.

We also engage in hedging activities as discussed below in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Hedging Activities.”

Competition

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources than us. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, obtaining sufficient availability of drilling and completion equipment and services, and hiring and retaining key employees. There is also competition among oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the U.S. government and the states in which our properties are located. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations.

Other Business Matters

Major Customers

The purchasers of our oil, natural gas and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. In 2015, three individual purchasers of our production, PetroQuest Energy, LLC, GulfMark Energy, Inc. and Genesis Crude Oil, LP accounted for 67% of our total sales for the year.

In 2014, three individual purchasers of our production, PetroQuest Energy, LLC, GulfMark Energy, Inc. and Gavilon, LLC accounted for 73% of our total sales for the year.

In 2013, four individual purchasers of our production, PetroQuest Energy, LLC, GulfMark Energy, Inc., Hilcorp Energy Company and Genesis Crude Oil, L. P., accounted for 78% of our total sales for the year.

We believe there are adequate alternate purchasers of our production such that the loss of one or more of the above purchasers would not have a material adverse effect on our results of operations or cash flows.

Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

Operational Risks

Oil and natural gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental leakage or spills of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.
 
 
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As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our operating results, financial position or cash flows. For further discussion of risks see Item 1A. “Risk Factors” of this report.

Title to Properties

We believe that the title to our oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and natural gas industry, subject to such exceptions which, in our belief, are not so material as to detract substantially from the use or value of such 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 natural 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.

Regulations

All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas properties, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the establishment of maximum allowable rates of production from fields and individual wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of land and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of land and leases. In areas where pooling is primarily or exclusively voluntary, it may be difficult to form spacing units and therefore difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration and production to proceed.
 
 
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The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Environmental Regulations

Our operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the United States Environmental Protection Agency, commonly referred to as the EPA, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Among other things, environmental regulatory programs typically regulate the permitting, construction and operation of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Failure to comply with environmental laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.

New programs and changes in existing programs, however, may address various aspects of our business including natural occurring radioactive materials, oil and natural gas exploration and production, air emissions, waste management, and underground injection of waste material. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, earnings and competitive position.

Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons may include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

Under the federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, most wastes generated by the exploration and production of oil and natural gas are not regulated as hazardous waste. Periodically, however, there are proposals to lift the existing exemption for oil and natural gas wastes and reclassify them as hazardous wastes. If such proposals were to be enacted, they could have a significant impact on our operating costs, as well as the oil and natural gas industry in general. In the ordinary course of our operations moreover, some wastes generated in connection with our exploration and production activities may be regulated as solid waste under RCRA, as hazardous waste under existing RCRA regulations or as hazardous substances under CERCLA. From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we have been and may be required to remove or remediate such materials or wastes.
 
 
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Water Discharges

Our operations are also subject to the federal Clean Water Act and analogous state laws. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff. We believe that we will be able to obtain, or be included under, these permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on us. The Clean Water Act and similar state acts regulate other discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil.

Our oil and natural gas production also generates salt water, which we dispose of by underground injection.  The federal Safe Drinking Water Act (“SDWA”), the Underground Injection Control (“UIC”) regulations promulgated under the SDWA and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

Hydraulic Fracturing

Our completion operations are subject to regulation, which may increase in the short- or long-term. The well completion technique known as hydraulic fracturing is used to stimulate production of natural gas and oil has come under increased scrutiny by the environmental community, and local, state and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate oil and natural gas production.

Under the direction of Congress, the EPA has undertaken a study of the effect of hydraulic fracturing on drinking water and groundwater. The EPA has also announced its plan to propose pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations. Congress may consider legislation to amend the SDWA to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have issued similar disclosure rules. Several environmental groups have also petitioned the EPA to extend toxic release reporting requirements under the Emergency Planning and Community Right-to-Know Act to the oil and natural gas extraction industry. Additional disclosure requirements could result in increased regulation, operational delays, and increased operating costs that could make it more difficult to perform hydraulic fracturing.

Air Emissions

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and natural gas production. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants.

Recently, the EPA issued four new regulations for the oil and natural gas industry, including: a new source performance standard for volatile organic compounds (“VOCs”); a new source performance standard for sulfur dioxide; an air toxics standard for oil and natural gas production; and an air toxics standard for natural gas transmission and storage. The final rule includes the first federal air standards for natural gas wells that are hydraulically fractured, or refractured, as well as requirements for several sources, such as storage tanks and other equipment, and limits methane emissions from these sources. Compliance with these regulations will impose additional requirements and costs on our operations.
 
 
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In October 2015, the EPA issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The final rule became effective in December 2015. Certain areas of the country in compliance with the ground-level ozone NAAQS standard may be reclassified as non-attainment and such reclassification may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Moreover, states are expected to implement more stringent regulations, which could apply to our operations. Compliance with this final rule could, among other things, require installation or new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

Climate Change

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several countries including those comprising the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the emission inventories, emissions targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

At the federal level, the EPA has issued regulations requiring us and other companies to annually report certain greenhouse gas emissions from our oil and natural gas facilities. Beyond its measuring and reporting rules, the EPA has issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities.

In August 2015, the EPA proposed rules that will establish emission standards for methane from certain new and modified oil and natural gas production and natural gas processing and transmission facilities as part of the Obama Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. The EPA’s proposed rule package includes standards to address emissions of methane from equipment and processes across the source category, including hydraulically-fractured oil and natural gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural gas processing plants and pneumatic pumps. The EPA is expected to finalize these rules in 2016.

The U.S. Congress and the EPA, in addition to some state and regional efforts, have in recent years considered legislation or regulations to reduce emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, and GHG reporting and tracking programs. In the absence of federal GHG-limiting legislations, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets.
 
 
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Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions control systems or other compliance costs, and reduce demand for our products.

The National Environmental Policy Act

Oil and natural gas exploration and production activities may be subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Although the Company has a few future projects that could potentially involve federal lands, federal lands require governmental permits that are subject to the requirements of NEPA.   This process has the potential to delay the development of future oil and natural gas projects.

Threatened and endangered species, migratory birds and natural resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. The United States Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and natural gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties.

Hazard communications and community right to know

We are subject to federal and state hazard communication and community right to know statutes and regulations. These regulations govern record keeping and reporting of the use and release of hazardous substances, including, but not limited to, the federal Emergency Planning and Community Right-to-Know Act and may require that information be provided to state and local government authorities and the public.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees.

Employees and Principal Office

As of December 31, 2015, we had 30 full-time employees. We hire independent contractors on an as-needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Our principal executive office is located at 1177 West Loop South, Suite 1825, Houston, Texas 77027, where we occupy approximately 15,180 square feet of office space. Our Bakersfield office, consisting of approximately 4,200 square feet, is located at 2008 Twenty-First Street, Bakersfield, California 93301.

We owned the following real property as of December 31, 2015, all located in Kern County in the State of California: Mullaney yard (20 acres), Miller property (112 acres), Ranton property (80 acres), Murphy property (50 acres) and in the City of Bakersfield (three town lots).
 
 
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Executive Officers of the Company

The following table sets forth the names and ages of all of our executive officers, the positions and offices with us held by such persons and the months and years in which continuous service as executive officers began:

Name
 
Executive Officer Since
 
Age
 
Position
Sam L. Banks
 
September 2014
 
66
 
Chairman of the Board, President and Chief Executive Officer
James J. Jacobs
 
December 2015
 
38
 
Chief Financial Officer, Treasurer and Corporate Secretary
Paul D. McKinney
 
October 2014
 
57
 
Executive Vice President and Chief Operating Officer

The following paragraphs contain certain information about each of our executive officers.

Sam L. Banks has been our Chief Executive Officer and Chairman of the Board of Directors since the closing of the merger on September 10, 2014 and also our President since October 10, 2014. He was the Chief Executive Officer and Chairman of the board of directors of Yuma Co. and its predecessor since 1983. He was also the founder of Yuma Co. He has 39 years of experience in the oil and natural gas industry, the majority of which he has been leading Yuma Co. Prior to founding Yuma Co., he held the position of Assistant to the President of Tomlinson Interests, a private independent oil and gas company. Mr. Banks graduated with a Bachelor of Arts from Tulane University in New Orleans, Louisiana, in 1972, and in 1976 he served as Republican Assistant Finance Chairman for the re-election of President Gerald Ford, under former Secretary of State, Robert Mosbacher.

James J. Jacobs has been our Chief Financial Officer, Treasurer and Corporate Secretary since December 2015. He served as our Vice President – Corporate and Business Development immediately prior to his appointment as Chief Financial Officer in December 2015 and has been with us since 2013. He has 15 years of experience in the financial services and energy sector. In 2001, Mr. Jacobs worked as an Energy Analyst at Duke Capital Partners. In 2003, Mr. Jacobs worked as a Vice President of Energy Investment Banking at Sanders Morris Harris where he participated in capital markets financing, mergers and acquisitions, corporate restructuring and private equity transactions for various sized energy companies. From 2006 through 2013, Mr. Jacobs was the Chief Financial Officer, Treasurer and Secretary at Houston America Energy Corp., where he was responsible for financial accounting and reporting for U.S. and Colombian operations, as well as capital raising activities. Mr. Jacobs graduated with a Master’s Degree in Professional Accounting and a Bachelor of Business Administration from the University of Texas in 2001.

Paul D. McKinney has been our Executive Vice President and Chief Operating Officer since October 2014. Mr. McKinney served as a petroleum engineering consultant for our predecessor from June 2014 to September 2014 and for us from September 2014 to October 2014. Mr. McKinney served as Region Vice President, Gulf Coast Onshore, for Apache Corporation from 2010 through 2013, where he was responsible for the development and all operational aspects of the Gulf Coast region for Apache. Prior to his role as Region Vice President, Mr. McKinney was Manager, Corporate Reservoir Engineering, for Apache from 2007 through 2010. From 2006 through 2007, Mr. McKinney was Vice President and Director, Acquisitions & Divestitures for Tristone Capital, Inc. Mr. McKinney commenced his career with Anadarko Petroleum Corporation and held various positions with Anadarko over a 23 year period from 1983 to 2006, including his last title as Vice President of Reservoir Engineering, Anadarko Canada Corporation. Mr. McKinney has a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University.

Available Information

Our principal executive offices are located at 1177 West Loop South, Suite 1825, Houston, Texas 77027. Our telephone number is (713) 768-7000. You can find more information about us at our website located at www.yumaenergyinc.com. Our Annual Report on Form 10-K (as amended by Form 10-K/A), our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and any amendments to those reports are available free of charge on or through our website, which is not part of this report. These reports are available as soon as reasonably practicable after we electronically file these materials with, or furnish them to, the SEC.  Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.
 
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Item 1A.                      Risk Factors.

We are subject to numerous risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in the foregoing pages under “Cautionary Statement Regarding Forward-Looking Statements” and other information included and incorporated by reference into this Annual Report on Form 10-K.
 
We have restated our prior consolidated financial statements, which may lead to additional risks and uncertainties, including loss of investor confidence and negative impacts on our stock price.
 
As discussed in the Explanatory Note and Note 26 – Restatement of Previously Issued Financial Statements in the Notes to the Consolidated Financial Statements to our consolidated financial statements included in this Form 10-K/A, we have restated our audited consolidated financial statements as of December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013 and our unaudited consolidated financial statements for all interim periods commencing with the quarter ended March 31, 2014 through the quarter ended December 31, 2015 (the “Restated Periods”). The determination to restate the financial statements for the Restated Periods was made by our Audit Committee upon management’s recommendation following the identification of non-cash errors in the computation of our income tax provision and the recording of our deferred taxes related to our asset retirement obligations, our stock based compensation, our allocation of the purchase price in the Pyramid merger and resultant amount of goodwill, the tax amortization of that goodwill, the tax treatment of expenses related to the Pyramid merger, the incorrect roll forward of the historic net operating losses and the difference in the book and tax basis in our properties.  As a result, our income tax provision and the net amount of our deferred tax liability were restated for the years ended December 31, 2015, 2014 and 2013 and the applicable quarterly periods in 2015 and 2014. Due to the errors, our Audit Committee concluded that our previously issued financial statements for the Restated Periods should no longer be relied upon. Our Annual Report on Form 10-K for the year ended December 31, 2015 has been amended to, among other things, reflect the restatement of our financial statements for the Restated Periods (the “Restatement”).
 
As a result of these events, we have become subject to a number of additional costs and risks, including unanticipated costs for accounting and legal fees in connection with or related to the Restatement and the remediation of our ineffective disclosure controls and procedures and material weakness in internal control over financial reporting. In addition, the attention of our management team has been diverted by these efforts. We could be subject to additional shareholder, governmental, or other actions in connection with the Restatement or other matters. Any such proceedings will, regardless of the outcome, consume a significant amount of management’s time and attention and may result in additional legal, accounting, insurance and other costs. If we do not prevail in any such proceedings, we could be required to pay substantial damages or settlement costs. In addition, the Restatement and related matters could impair our reputation or could cause our counterparties to lose confidence in us. Each of these occurrences could have a material adverse effect on our business, results of operations, financial condition and stock price which could, among other items, result in a default under the Company’s financing agreements.
 
We have identified a material weakness in our internal control over financial reporting. Our failure to establish and maintain effective internal control over financial reporting could result in material misstatements in our financial statements and cause investors to lose confidence in our reported financial information, which in turn could cause the trading price of our securities to decline.
 
We have identified a material weakness in our internal control over financial reporting related to the appropriate policies and procedures in place to properly evaluate the accuracy and presentation of our accounting for income taxes, including the income tax provisions and related deferred tax assets and liabilities and, as a result of such weakness, our management concluded that our disclosure controls and procedures and internal control over financial reporting were not effective as of December 31, 2015. This resulted in the restatement of our (i) consolidated balance sheets as of December 31, 2015 and 2014, (ii) consolidated statements of operations, consolidated statements of comprehensive income (loss), consolidated statements of changes in equity and consolidated statements of cash flows for the years ended December 31, 2015, 2014 and 2013 and (iii) unaudited quarterly financial information for the quarters ended March 31, 2014 through December 31, 2015. For further information regarding this matter and the related material weakness, please refer to Item 9A. Controls and Procedures.
 
 
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In addition, we may experience delay or be unable to meet our reporting obligations or to comply with SEC rules and regulations, which could result in investigations and sanctions by regulatory authorities. Management’s ongoing assessment of disclosure controls and procedures as well as internal control over financial reporting may in the future identify additional weaknesses and conditions that need to be addressed. Any failure to improve our disclosure controls and procedures or internal control over financial reporting to address identified weaknesses in the future, if they were to occur, could prevent us from maintaining accurate accounting records and discovering material accounting errors, which in turn, could adversely affect our business and the value of our common stock and our preferred stock.

Due to low current commodity prices, we anticipate that we may be required to take write-downs of the carrying values of our properties in 2016.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties.  A write-down constitutes a non-cash charge to earnings. Based upon commodity prices as of March 31, 2016, we do not expect that we will incur an impairment charge in the first quarter of 2016, but we may incur impairments in future periods.

Our short-term liquidity is significantly constrained, and could severely impact our cash flow and our development of our properties.

Currently, our principal sources of liquidity are cash flow from our operations and borrowing under our credit facility. During the year ended December 31, 2015, we borrowed $6.9 million under our credit facility to fund a portion of our capital expenditures. On December 30, 2015, we entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment to our credit agreement (the “Amendment”), which reduced our borrowing base to $29.8 million and automatically reduces our borrowing base to $20.0 million on May 31, 2016. As of March 29, 2016, our total borrowing base was $29.8 million with no remaining availability.  This reduction severely limits our liquidity and limits our expenditures to our current cash flow. Furthermore, the Amendment automatically reduces our borrowing base by $9.8 million to $20.0 million on May 31, 2016. Accordingly, we will be in default under our credit agreement if we do not repay $9.8 million by May 31, 2016 or obtain an extension from our lenders. As a condition to the merger with Davis, we will need to enter into an amendment to our credit agreement to take into account the properties of Davis, which we anticipate will help our liquidity; however, we do not anticipate closing our merger with Davis until the middle of 2016 and will need to obtain a waiver from our lenders, which they may not provide. Additionally, the merger with Davis is subject to approval by our shareholders, including at least two-thirds of the shares of our Series A Preferred Stock. At this time, we have little capital to develop our properties.

Our audited financial statements for the year ended December 31, 2015 contain a going-concern qualification, raising questions as to our continued existence.

Our independent auditors have issued a going concern opinion, which means that there is substantial doubt about our ability to continue as a going concern. As of the date of this report, we will require additional funds for the balance of fiscal year 2016 to repay $9.8 million under our credit agreement when our borrowing base is reduced to $20.0 million on May 31, 2016 and to continue our operations. If we cannot raise these funds or complete the merger with Davis, we may be required to significantly alter our business plan, reduce our activities, sell assets, or we could be forced into bankruptcy or liquidation. These financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts and classification of liabilities that might result from the possible inability to continue as a going concern.

Our credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices.

The terms of our credit agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable.
 
 
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The credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. For example, our lenders have reduced our borrowing base from $29.8 million to $20.0 effective May 31, 2016. Significant recent decreases in the price of crude oil are likely to have an adverse effect on our borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the credit facility. We anticipate that our merger with Davis will add substantial properties that may be pledged under our credit agreement; however, if the Davis merger is not approved by our shareholders, including at least two-thirds of the shares of our Series A Preferred Stock, we will not be able to complete the merger with Davis.  Our inability to borrow additional funds under our credit facility could adversely affect our operations and our financial results, and possibly force us into bankruptcy or liquidation.

If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there would be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on our indebtedness and satisfy our other obligations.

Any default under the agreements governing our indebtedness, including a default under our credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to seek to obtain waivers from the required lenders under our credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs, we would be in default under our credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease.

Oil and natural gas prices are volatile. A substantial or extended decline in commodity prices will likely adversely affect our business, financial condition and results of operations and our ability to meet our debt commitments, or capital expenditure obligations and other financial commitments.

Prices for oil, natural gas, and natural gas liquids can fluctuate widely. For example, the NYMEX West Texas Intermediate oil prices have been volatile and ranged from a high of $107.26 per barrel in June 2014 to a low of $26.21 per barrel in February 2016. Also, NYMEX Henry Hub natural gas prices have been volatile and ranged from a high of $6.15 per million British thermal units (MMBtu) in February 2014 to a low of $1.64 per MMBtu in December 2015. Our revenues, profitability and our future growth and the carrying value of our properties depend substantially on prevailing oil and natural gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we will be able to borrow under our credit agreement is subject to periodic redetermination based in part on current oil and natural gas prices and on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our properties.
 
 
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Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:

● 
the domestic and foreign supply of, and demand for, oil and natural gas;
 
● 
volatility and trading patterns in the commodity-futures markets;
 
● 
the ability of members of OPEC and other producing countries to agree upon and determine oil prices and production levels;
 
● 
social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States, such as Africa and the Middle East, and armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;
 
● 
the level of consumer product demand;
 
● 
the growth of consumer product demand in emerging markets, such as China;
 
● 
labor unrest in oil and natural gas producing regions;
 
● 
weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;
 
● 
the price and availability of alternative fuels;
 
● 
the price of foreign imports;
 
● 
worldwide economic conditions; and
 
● 
the availability of liquid natural gas imports.

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas.

The long-term effect of these and other factors on the prices of oil and natural gas is uncertain. Prolonged or further declines in these commodity prices may have the following effects on our business:
 
● 
adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations;

● 
reducing the amount of oil and, natural gas that we can produce economically;

● 
causing us to delay or postpone a significant portion of our capital projects;

● 
materially reducing our revenues, operating income, or cash flows;

● 
reducing the amounts of our estimated proved oil and natural gas reserves;

● 
reducing the carrying value of our oil and natural gas properties due to recognizing additional impairments of proved properties, unproved properties and exploration assets;

● 
reducing the standardized measure of discounted future net cash flows relating to oil and natural gas reserves; and

● 
limiting our access to, or increasing the cost of, sources of capital such as equity and long-term debt.
 
 
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Our operations and future development activities are concentrated in the Greater Masters Creek Field in west central Louisiana. In the event the field does not meet our expectations with respect to drilling and future production or we are unable to develop the field due to capital constraints, our future business, financial condition and results of operations will be materially adversely affected.
 
As set forth elsewhere in this report, our Greater Masters Creek Field in west central Louisiana is our largest oil and natural gas development project. At December 31, 2015, we held approximately 61,986 net acres in the field. Although the acreage has been partially developed by prior operators, our internal geological and engineering evaluation, as substantiated by two independent third-party engineering firms, supports the presence of significant remaining proved and non-proved undeveloped reserves and additional potential. Our independent petroleum engineering reserve report as of December 31, 2015 includes 22 operated proved undeveloped well locations and three non-operated proved undeveloped well locations, 63 operated non-proved undeveloped locations, and 11 non-operated non-proved undeveloped locations that are held by production or contain existing leasehold.

In December of 2014, we completed our second operated Austin Chalk well, the Crosby 14-1. While this well encountered bottom-hole pressure consistent with our third-party engineering estimates and demonstrated encouraging initial production results, we encountered significant mechanical difficulties while drilling and completing the well that eventually led to problems producing the well. Due to restrictions in the horizontal section of the well bore, including down-hole drilling motor components, we were not able to run a slotted liner which is used to prevent, among other things, formation and drilling debris from entering the wellbore during production operations.  Subsequent attempts to maintain sustained and economic production from the well failed because formation and drilling debris continued to plug the well.  The well last produced in April 2015 and was subsequently shut-in.

As of December 31, 2015, the field contained approximately 84.1% of our total proved undeveloped reserves and 83.7% of the PV-10 of such reserves. Additionally, the field’s proved undeveloped reserves represent approximately 61.7% of our total proved reserves. Because such a significant portion of our operations are concentrated in the field, the success of our operations and our profitability may be disproportionately exposed to the effect of various events with respect to the field, including but not limited to unanticipated costs and delays in drilling, fluctuations in prices of natural gas and oil produced from wells, natural disasters, restrictive governmental regulations, transportation capacity constraints, inclement weather, curtailment of production due to unforeseen events, and any resulting delays or interruptions of production from existing or planned new wells in the field.  We are currently seeking joint venture partners to participate in the future drilling and development of these locations, which would reduce our participating interest in these locations and thereby reduce our future capital expenditures and associated proved and non-proved reserves and production.  We plan to drill one proved undeveloped well this year and the remaining proved undeveloped wells within five years from the date they were originally recorded.   However, in the event our assumptions and analyses regarding the field are incorrect to any significant degree, the future production from the wells to be drilled may be adversely affected, which in turn could materially adversely affect our business, financial condition and results of operations. In addition, our development plan as of January 1, 2016 assumes that the net capital for development of the field will be approximately $105 million over four years. Our ability to have sufficient capital in accordance with our plan to complete the development of these undeveloped reserves will be subject to our future cash flows, future prices for oil and gas, our ability to bring in other partners, as well as our capital raising abilities. Any significant sustained decrease in the price of oil and gas or our ability to obtain financing, either debt or equity, or attract joint venture partners would have a significant negative impact on our ability to develop the field as planned and hence, realize the positive cash flow and net income as estimated elsewhere in this report.

We may not be able to drill wells on a substantial portion of our acreage.

We may not be able to drill on a substantial portion of our acreage for various reasons. We may not generate or be able to raise sufficient capital to do so. Further deterioration in commodities prices may also make drilling certain acreage uneconomic. Our actual drilling activities and future drilling budget will depend on drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, lease expirations, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, any drilling activities we are able to conduct may not be successful or add additional proved reserves to our overall proved reserves, which could have a material adverse effect on our future business, financial condition and results of operations.

 
 
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A significant portion 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.
 
A significant portion of our net leasehold acreage is 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. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income, are dependent on successfully developing our undeveloped leasehold acreage.

Our undeveloped acreage must be drilled before lease expirations to hold the acreage by production. Failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our undeveloped leases and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. Approximately 79% of our total Masters Creek undeveloped acreage will be subject to expiration in 2016, with 20% of such acreage expiring in 2017, and 1% in 2018. As of December 31, 2015, leases representing 76%, 23%, and 1%, respectively, of our total undeveloped acreage are scheduled to expire in 2016, 2017, and 2018. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. If we are unable to fund renewals of expiring leases, we could lose portions of our acreage and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.

Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.

If the amount of natural gas, condensate or oil being produced by us and others exceeds the capacity of the various transportation pipelines and gathering systems available in our operating areas, it will be necessary for new transportation pipelines and gathering systems to be built. Or, in the case of oil and condensate, it will be necessary for us to rely more heavily on trucks to transport our production, which is more expensive and less efficient than transportation via pipeline. The construction of new pipelines and gathering systems is capital intensive and construction may be postponed, interrupted or cancelled in response to changing economic conditions and the availability and cost of capital. In addition, capital constraints could limit our ability to build gathering systems to transport our production to transportation pipelines. In such event, costs to transport our production may increase materially or we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at much lower prices than market or than we currently project, which would adversely affect our results of operations.

A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of operational issues, mechanical breakdowns, weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our financial condition, results of operations and cash flows.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well. Estimates of the decline rate of an oil or natural gas well are inherently imprecise, and are less precise with respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations with established production histories. Our production levels and the reserves that we currently expect to recover from our wells will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, our cash flow and the value of our reserves may decrease, adversely affecting our business, financial condition, results of operations, and potentially the borrowing capacity under our credit facility.
 
 
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Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions will materially affect the quantities and the net present value of our reserves.

This report contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the net present value of our reserves. For instance, the SEC mandated prices used in estimating our proved reserves are $50.28 per Bbl of oil and $2.59 per MMBtu of natural gas, which are significantly higher than current spot market prices.  Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

At December 31, 2015, approximately 73.3% of our estimated reserves were classified as proved undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. The estimates of these oil and natural gas reserves and the costs associated with development of these reserves have been prepared in accordance with SEC regulations; however, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2015, 2014 and 2013, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:
 
● 
actual prices we receive for oil and natural gas;

● 
actual cost of development and production expenditures;

● 
the amount and timing of actual production; and

● 
changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.  As a corporation, we are treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this report which could have a material effect on the value of our reserves.
 
 
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We depend on computer and telecommunications systems and failures in our systems or cyber security attacks could significantly disrupt our business operations.

We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. It is possible we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties to our computing and communications infrastructure or our information systems could significantly disrupt our business operations.

We depend substantially on our key personnel for critical management decisions and industry contacts.

Our success depends upon the continued contributions of our executive officers and key employees, particularly with respect to providing the critical management decisions and contacts necessary to manage and maintain our company within a highly competitive industry. Competition for qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. Under these conditions, we could be unable to attract and retain these personnel. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.

Our business is highly competitive.

The oil and natural gas industry is highly competitive in many respects, including identification of attractive oil and natural gas properties for acquisition, drilling and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities. In seeking suitable opportunities, we compete with a number of other companies, including large oil and natural gas companies and other independent operators with greater financial resources, larger numbers of personnel and facilities, and, in some cases, with more expertise.  There can be no assurance that we will be able to compete effectively with these entities.

Our oil and natural gas activities are subject to various risks which are beyond our control.

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we may take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and natural gas in commercial and economic quantities, the rate of production and the economics of the development of, and our investment in the prospects in which we have or will acquire an interest. Any of these risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows. Such risks and hazards include:

● 
human error, accidents, labor force and other factors beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;
 
● 
blowouts, fires, hurricanes, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment and increased drilling and production costs;
 
● 
unavailability of materials and equipment;
 
● 
engineering and construction delays;
 
● 
unanticipated transportation costs and delays;
 
● 
unfavorable weather conditions;
 
● 
hazards resulting from unusual or unexpected geological or environmental conditions;
 
● 
environmental regulations and requirements;
 
● 
accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or salt water, into the environment;
 
 
28

 
 
● 
hazards resulting from the presence of hydrogen sulfide or other contaminants in natural gas we produce;
 
● 
changes in laws and regulations, including laws and regulations applicable to oil and natural gas activities or markets for the oil and natural gas produced;
 
● 
fluctuations in supply and demand for oil and natural gas causing variations of the prices we receive for our oil and natural gas production; and
 
● 
the availability of alternative fuels and the price at which they become available.

As a result of these risks, expenditures, quantities and rates of production, revenues and operating costs may be materially affected and may differ materially from those anticipated by us.

Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.

We require significant amounts of undeveloped leasehold acreage to further our development efforts. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage that we believe will result in projects that will add value over time. However, we cannot guarantee that our leasehold acreage will be profitably developed, that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results is dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling and completing a well, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:

● 
unexpected drilling conditions;
 
● 
downhole and well completion difficulties;
 
● 
pressure or irregularities in formations;
 
● 
equipment failures or breakdowns, or accidents and shortages or delays in the availability of drilling and completion equipment and services;
 
● 
fires, explosions, blowouts and surface cratering;
 
● 
adverse weather conditions, including hurricanes; and
 
● 
compliance with governmental requirements.
 
 
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We are subject to complex federal, state, local and other laws and regulations that from time to time are amended to impose more stringent requirements that could adversely affect the cost, manner or feasibility of doing business.

Companies that explore for and develop, produce, sell and transport oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax and environmental, health and safety laws and the corresponding regulations, and are required to obtain various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

● 
water discharge and disposal permits for drilling operations;
 
● 
drilling bonds;
 
● 
drilling permits;
 
● 
reports concerning operations;
 
● 
air quality, air emissions, noise levels and related permits;
 
● 
spacing of wells;
 
● 
rights-of-way and easements;
 
● 
unitization and pooling of properties;
 
● 
pipeline construction;
 
● 
gathering, transportation and marketing of oil and natural gas;
 
● 
taxation; and
 
● 
waste transport and disposal permits and requirements.

Failure to comply with applicable laws may result in the suspension or termination of operations and subject us to liabilities, including administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, the laws governing our operations or the enforcement thereof could change in ways that substantially increase the costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of operations. Under environmental, health and safety laws and regulations, we also could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages including the assessment of natural resource damages. Such laws may impose strict as well as joint and several liability for environmental contamination, which could subject us to liability for the conduct of others or for our own actions that were in compliance with all applicable laws at the time such actions were taken. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to regulation by oil and natural gas-producing states relating to conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. Delays in obtaining regulatory approvals or necessary permits, the failure to obtain a permit or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on, develop or produce our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Federal, state, tribal and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we have operated and non-operated working interests and the operator of such properties could be subject to additional levels of regulation, operational delays or increased operating costs and could have regulatory burdens imposed upon it that could make it more difficult to perform hydraulic fracturing and increase the costs of compliance and doing business.

From time to time, for example, legislation has been proposed in Congress to amend the Safe Drinking Water Act (“SDWA”) to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process.  Further, the EPA is conducting a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. In December 2015, the EPA issued a draft final report for public comment and peer review. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing.  For example, a BLM rulemaking for hydraulic fracturing practices on federal and Indian lands resulted in a 2015 final rule that requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. These activities could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business with regard to our operated and non-operated properties.
 
 
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Certain states likewise have adopted, and other states are considering the adoption of regulations that impose new or more stringent requirements for various aspects of hydraulic fracturing operations, such as permitting, disclosure, air emissions, well construction, seismic monitoring, waste disposal and water use. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. Such efforts have extended to bans on hydraulic fracturing.

As a working interest owner, we use a significant amount of water with respect to hydraulic fracturing operations. The inability to locate sufficient amounts of water, or dispose of or recycle water used in exploration and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to participate in certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. Compliance with environmental regulations and regulatory permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase the operating costs of our properties and cause delays, interruptions or termination of operations, all of which could have an adverse effect on our results of operations and financial condition. Further, if the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.

Hydraulic fracturing involves the injection of water, sand and various chemicals under pressure into geologic formations to fracture the surrounding rock and stimulate production. This process may give rise to operational issues such as an underground migration of water and chemicals to unintended areas, wellbore integrity, possible surface spillage and contamination caused by mishandling of fracturing fluids, including chemical additives. Properly administering the hydraulic fracturing process entails operational costs and a failure to properly administer the process could cause significant remedial and financial costs.

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and international negotiations over climate change and greenhouse gases are continuing.  Meanwhile, several countries, including those comprising the European Union, have established greenhouse gas regulatory systems.

In the United States, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emission targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

At the federal level, the Obama Administration is attempting to address climate change through a variety of administrative actions. The EPA has issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. On July 19, 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting beginning in September 2012. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, the President released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and gas sector. Towards that end, the EPA released five draft white papers on methane and volatile organic compound emissions and mitigation measures for natural gas compressors, hydraulically fractured oil wells, pneumatic devices, well liquids unloading facilities and natural gas production and transmission facilities. Building on its white papers and the public input on those documents, the EPA issued a proposed rule in 2015 that would set additional standards for methane and emissions from oil and gas production sources, including hydraulically fractured oil wells and natural gas processing and transmission sources.  The EPA intends to issue a final rule in 2016.  In addition, the BLM has proposed standards for reducing venting and flaring on public lands.  The EPA and BLM actions are part of a series of steps by the Administration that are intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas industry as compared to 2012 levels.
 
 
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In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls to obtain emission allowances or to pay emission taxes, and reduce demand for our products.

The ongoing implementation of federal legislation enacted in 2010 could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the SEC and the Commodity Futures Trading Commission (the “CFTC”), along with other federal agencies, to promulgate regulations implementing the new legislation. The CFTC, in coordination with the SEC and various U.S. federal banking regulators, has issued regulations to implement the so-called “Volcker Rule” under which banking entities are generally prohibited from proprietary trading of derivatives. Although conditional exemptions from this general prohibition are available, the Volcker Rule may limit the trading activities of banking entities that have been counterparties to our derivatives trades in the past.

The CFTC also has finalized other regulations implementing the Dodd-Frank Act’s provisions regarding trade reporting, margin and position limits; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible that under recently adopted margin rules, some CFTC registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.

The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

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

The Obama administration has proposed to eliminate certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The proposals include, but are not limited to (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. In addition, President Obama has recently proposed a $10.25 per barrel tax on oil companies. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could result in higher federal income taxes, which could negatively affect our financial condition and results of operations. In addition, proposals are made from time to time in states where we operate to implement or increase severance or other taxes at the state level, and any such additional taxes would have similarly adverse effects on us.
 
 
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We participate in oil and natural gas leases with third parties who may not be able to fulfill their commitments to our projects.

We frequently own less than 100% of the working interest in the oil and natural gas leases on which we conduct operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil and natural gas prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.

We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:

● 
personal injury;
 
● 
bodily injury;
 
● 
third party property damage;
 
● 
medical expenses;
 
● 
legal defense costs;
 
● 
pollution in some cases;
 
● 
well blowouts in some cases; and
 
● 
workers compensation.

As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our financial position, results of operations and cash flows.  There can be no assurance that the insurance coverage that we maintain will be sufficient to cover claims made against us in the future.

Title to the properties in which we have an interest may be impaired by title defects.

We generally obtain title opinions on significant properties that we drill or acquire. However, there is no assurance that we will not suffer a monetary loss from title defects or title failure.  Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
 
 
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The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

The oil and natural gas industry is cyclical and, from time to time, there have been shortages of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies or qualified personnel can materially and adversely affect our operations and profitability.

We depend on the skill, ability and decisions of third-party operators of the oil and natural gas properties in which we have a non-operated working interest.

The success of the drilling, development and production of the oil and natural gas properties in which we have or expect to have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of third-party operators to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could materially affect our results of operations.

Hedging transactions may limit our potential gains and increase our potential losses.

In order to manage our exposure to price risks in the marketing of our oil, natural gas, and natural gas liquids production, we have entered into oil, natural gas, and natural gas liquids price hedging arrangements with respect to a portion of our anticipated production and we may enter into additional hedging transactions in the future. While intended to reduce the effects of volatile commodity prices, such transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

● 
our production is less than expected;
 
● 
there is a widening of price differentials between delivery points for our production; or
 
● 
the counterparties to our hedging agreements fail to perform under the contracts.

A component of our growth may come through acquisitions, and our failure to identify or complete future acquisitions successfully could reduce our earnings and slow our growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees.

In addition, we may be unable to successfully integrate any potential acquisitions into our existing operations. The inability to manage the integration of acquisitions, including our merger with Davis, effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Members of our management team may be required to devote considerable amounts of time to the integration process, including with respect to the merger of Davis, which will decrease the time they will have to manage our business.
 
 
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Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods.

We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. Our credit agreement includes covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests.

We may be unsuccessful in combining Davis’ business with our existing business.

The success of the proposed merger of Davis will depend, in part, on our ability to realize the anticipated benefits and synergies from combining our business and existing asset base with the business of Davis and the assets obtained in the merger of Davis. To realize these anticipated benefits, the businesses must be successfully integrated. If we are not able to achieve these objectives, or we are not able to achieve these objectives on a timely basis, the anticipated benefits of the merger of Davis may not be realized fully or at all. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger of Davis. These integration difficulties could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to the Ownership of our Common Stock

We are a “controlled company” within the meaning of the NYSE MKT rules and, as a result, qualify for, and rely on, exemptions from certain corporate governance requirements. As a result, our shareholders do not have the same protections afforded to shareholders of companies that are subject to such requirements.

Sam L. Banks, our Chairman, President and Chief Executive Officer, beneficially owns a majority of our common stock. As a result, we are a “controlled company” within the meaning of the NYSE MKT corporate governance standards. Under the NYSE MKT rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE MKT corporate governance requirements, including the requirements that:
 
● 
a majority of our board of directors consist of independent directors;
 
● 
we have a nominating committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
 
● 
we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

We are currently utilizing, and intend to continue to utilize, the exemption relating to the nominating committee, and we may utilize this exemption for so long as we are a controlled company. Accordingly, our shareholders do not have the same protections afforded to shareholders of companies that are subject to all of the corporate governance requirements of the NYSE MKT.

Our common stock price has been and is likely to continue to be highly volatile.

The trading price of our common stock is subject to wide fluctuations in response to a variety of factors, including quarterly variations in operating results, announcements of drilling and rig activity, economic conditions in the natural gas and oil industry, general economic conditions or other events or factors that are beyond our control.
 
 
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In addition, the stock market in general and the market for oil and natural gas exploration companies, in particular, have experienced large price and volume fluctuations that have often been unrelated or disproportionate to the operating results or asset values of those companies. These broad market and industry factors may seriously impact the market price and trading volume of our common stock regardless of our actual operating performance. In the past, following periods of volatility in the overall market and in the market price of a company’s securities, securities class action litigation has been instituted against certain oil and natural gas exploration companies. If this type of litigation were instituted against us following a period of volatility in our common stock trading price, it could result in substantial costs and a diversion of our management’s attention and resources, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

The low trading volume of our common stock may adversely affect the price of our shares and their liquidity.
 
Although our common stock is listed on the NYSE MKT exchange, our common stock has experienced low trading volume. Limited trading volume may subject our common stock to greater price volatility and may make it difficult for investors to sell shares at a price that is attractive to them.

If our common stock price declines, our common stock may be subject to delisting from the NYSE MKT.
 
Our common stock is currently trading at a price of less than $1.00 per share. We currently meet the continued listing standards of NYSE MKT. However, we cannot assure you that we will be able to continue to comply with the minimum bid price and the other standards that we are required to meet in order to maintain a listing of our common stock on the NYSE MKT. Our failure to continue to meet these requirements may result in our common stock being delisted from the NYSE MKT. If our common stock is delisted, this would, among other things, substantially impair our ability to raise additional funds and could result in a loss of institutional investor interest and fewer development opportunities for us.

If our common stock were delisted and determined to be a “penny stock,” a broker-dealer may find it more difficult to trade our common stock, and an investor may find it more difficult to acquire or dispose of our common stock in the secondary market.
 
If our common stock were removed from listing with the NYSE MKT, it may be subject to the so-called “penny stock” rules. The SEC has adopted regulations that define a penny stock to be any equity security that has a market price per share of less than $5.00, subject to certain exceptions, such as any securities listed on a national securities exchange. For any transaction involving a penny stock, unless exempt, the rules impose additional sales practice requirements on broker-dealers, subject to certain exceptions. If our common stock were delisted and determined to be a penny stock, a broker-dealer may find it more difficult to trade our common stock, and an investor may find it more difficult to acquire or dispose of our common stock on the secondary market.

We are able to issue shares of preferred stock with greater rights than our common stock.

Our Restated Articles of Incorporation authorize our board of directors to issue one or more series of preferred shares and set the terms of the preferred shares without seeking any further approval from our shareholders. The preferred shares that we have issued rank ahead of our common stock in terms of dividends and liquidation rights. We may issue additional preferred shares that rank ahead of our common stock in terms of dividends, liquidation rights or voting rights. If we issue additional preferred shares in the future, it may adversely affect the market price of our common stock. We have issued in the past, and may in the future continue to issue, in the open market at prevailing prices or in capital markets offerings series of perpetual preferred stock with dividend and liquidation preferences that rank ahead of our common stock.
 
Because we have no plans to pay dividends on our common stock, shareholders must look solely to appreciation of our common stock to realize a gain on their investment.

We do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain any future earnings to finance the expansion of our business. In addition, our credit agreement contains covenants that prohibit us from paying cash dividends on our common stock as long as such debt remains outstanding. 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. Accordingly, shareholders must look solely to appreciation of our common stock to realize a gain on their investment, which may not occur.
 
 
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Risks Related to the Ownership of our Series A Preferred Stock

The Series A Preferred Stock ranks junior to all of our indebtedness and other liabilities and is effectively junior to all indebtedness and other liabilities of our subsidiaries.

In the event of our bankruptcy, liquidation, dissolution or winding-up of our affairs, our assets will be available to pay obligations on the Series A Preferred Stock only after all of our indebtedness and other liabilities have been paid. The rights of holders of the Series A Preferred Stock to participate in the distribution of our assets will rank junior to the prior claims of our current and future creditors and any future series or class of preferred stock we may issue that ranks senior to the Series A Preferred Stock. As of March 29, 2016, 554,596 shares of Series A Preferred Stock, having a liquidation value of $25 per share, are outstanding. If we are forced to liquidate our assets to pay our creditors, we may not have sufficient assets to pay amounts due on any or all of the Series A Preferred Stock then outstanding. We and our subsidiaries have incurred and may in the future incur substantial amounts of debt and other obligations that will rank senior to the Series A Preferred Stock. At March 25, 2016, we had $29.8 million of bank debt, on a consolidated basis, ranking senior to the Series A Preferred Stock. Our credit facility prohibits payments of dividends on the Series A Preferred Stock if we fail to comply with certain financial covenants or, at certain times, if a default or event of default has occurred. Certain of our other existing or future debt instruments may restrict the authorization, payment or setting apart of dividends on the Series A Preferred Stock. Beginning with dividends accruing as of November 1, 2015, our board of directors suspended payment of dividends on the Series A Preferred Stock until such time as the Company has sufficient liquidity to restore payment of such dividends.

Future offerings of debt or senior equity securities may adversely affect the market price of the Series A Preferred Stock. If we decide to issue debt or senior equity securities in the future, it is possible that these securities will be governed by an indenture or other instruments containing covenants restricting our operating flexibility. Additionally, any convertible or exchangeable securities that we issue in the future may have rights, preferences and privileges more favorable than those of the Series A Preferred Stock and may result in dilution to owners of the Series A Preferred Stock. We and, indirectly, our shareholders, will bear the cost of issuing and servicing such securities. Because our decision to issue debt or equity securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings. The holders of the Series A Preferred Stock will bear the risk of our future offerings, reducing the market price of the Series A Preferred Stock and diluting the value of their holdings in us.

We may not be able to pay dividends in cash on the Series A Preferred Stock under California law.

Under California law, cash dividends may be paid only if either (1) our retained earnings exceed the amount of the distribution plus the amount, if any, of dividends in arrears on shares with preferential dividend rights, or (2) our total assets are not less than the sum of our total liabilities plus the amount that would be needed if we were to be dissolved at the time of the distribution to satisfy the preferential rights upon dissolution of shareholders whose preferential rights on dissolution are superior to those receiving the distribution. Further, notwithstanding these factors, we may not have sufficient cash to pay dividends on the Series A Preferred Stock. Our ability to pay dividends in the future may be impaired if any of the risks described in this report, were to occur. In addition, payment of our dividends depends upon our financial condition and other factors as our board of directors may deem relevant from time to time. We cannot make assurances 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 make distributions on our Series A Preferred Stock and pay accrued and unpaid dividends in the future, or to pay our indebtedness or to fund our other liquidity needs.

We do not expect to pay any cash dividends on our Series A Preferred Stock for the foreseeable future.

Our board of directors suspended the monthly cash dividend payment on the Series A Preferred Stock as a result of the depressed commodity price environment which has adversely affected our cash flows and liquidity. Accordingly, we do not anticipate that we will pay any cash dividends on shares of our Series A Preferred Stock for the foreseeable future. Any determination to pay dividends in the future will be at the discretion of our board of directors and will depend upon commodity prices, results of operations, financial condition, contractual restrictions, restrictions imposed by applicable law and other factors our board of directors deems relevant. In addition, we are currently limited in our ability to declare dividends or make distributions on account of our Series A Preferred Stock under the terms of our credit agreement.  Additionally, if dividends on our Series A Preferred Stock are in arrears and unpaid for six or more quarterly periods, the holders (voting as a single class) of our outstanding Series A Preferred Stock will be entitled to elect two additional directors to our board of directors until paid in full.
 
 
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The Series A Preferred Stock has not been rated.

We have not sought to obtain a rating for the Series A Preferred Stock. No assurance can be given, however, that one or more rating agencies might not independently determine to issue such a rating or that such a rating, if issued, would not adversely affect the market price of the Series A Preferred Stock. In addition, we may elect in the future to obtain a rating for the Series A Preferred Stock, which could adversely affect the market price of the Series A Preferred Stock. Ratings only reflect the views of the rating agency or agencies issuing the ratings and such ratings could be revised downward, placed on a watch list or withdrawn entirely at the discretion of the issuing rating agency if, in its judgment, circumstances so warrant. Any such downward revision, placing on a watch list, or withdrawal of a rating could have an adverse effect on the market price of the Series A Preferred Stock.

Holders of Series A Preferred Stock may not be able to exercise conversion rights upon a Change of Control, and, if exercisable, these conversion rights may not adequately compensate you.

Upon the occurrence of a Change of Control, each holder of the Series A Preferred Stock will have the right (unless, prior to the Change of Control Conversion Date, we have provided notice of our election to redeem some or all of the shares of Series A Preferred Stock held by such holder, in which case such holder will have the right only with respect to shares of Series A Preferred Stock that are not called for redemption) to convert some or all of such holder’s Series A Preferred Stock into shares of our common stock (or under specified circumstances involving certain alternative consideration).

Although we generally may not redeem the Series A Preferred Stock prior to October 23, 2017 (and we are subject to a general prohibition on redemptions under the terms of our credit facility prior to the date which is 30 days after all of our obligations and the lender commitments under those credit facilities have been satisfied), we have a special optional redemption right to redeem the Series A Preferred Stock in the event of a Change of Control, and holders of the Series A Preferred Stock will not have the right to convert any shares that we have elected to redeem prior to the Change of Control Conversion Date.

If we do not elect to redeem or are prohibited from redeeming the Series A Preferred Stock prior to the Change of Control Conversion Date, then, upon an exercise of the applicable conversion rights, the number of shares of our common stock or other applicable consideration that the holders of Series A Preferred Stock will be entitled to receive will be limited to a maximum of 14.12 multiplied by the number of shares of Series A Preferred Stock to be converted.

Notwithstanding the above, pursuant to the merger agreement with Davis, we have agreed as part of the reincorporation from California to Delaware, subject to approval of the holders of Series A Preferred Stock, to convert each share of our existing Series A Preferred Stock into 35 shares of common stock prior to giving effect for the reverse split (3.5 shares post reverse split).

The market price of the Series A Preferred Stock could be substantially affected by various factors.

The market price of the Series A Preferred Stock will depend on many factors, which may change from time to time, including:

 
● 
our suspension of the cash payment of dividends on the Series A Preferred Stock;

 
● 
prevailing interest rates, increases in which may have an adverse effect on the market price of the Series A Preferred Stock;

 
● 
trading prices of common and preferred equity securities issued by other energy companies;
 
 
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● 
the annual yield from distributions on the Series A Preferred Stock as compared to yields on other financial instruments;

 
 ● 
general economic and financial market conditions;

 
● 
government action or regulation;

 
● 
the financial condition, performance and prospects of us and our competitors;

 
● 
changes in financial estimates or recommendations by securities analysts with respect to us, or competitors in our industry;

 
● 
our issuance of additional preferred equity or debt securities; and

 
● 
actual or anticipated variations in quarterly operating results of us and our competitors.

As a result of these and other factors, investors who purchase the Series A Preferred Stock may experience a decrease, which could be substantial and rapid, in the market price of the Series A Preferred Stock, including decreases unrelated to our operating performance or prospects.

We may issue additional shares of Series A Preferred Stock and additional series of preferred stock that rank on parity with the Series A Preferred Stock as to dividend rights, rights upon liquidation, or voting rights.

We are allowed to issue additional shares of Series A Preferred Stock and additional series of preferred stock that would rank equally to the Series A Preferred Stock as to dividend payments and rights upon our liquidation, dissolution or winding up of our affairs pursuant to our restated articles of incorporation, as amended, and the certificate of determination for the Series A Preferred Stock without any vote of the holders of the Series A Preferred Stock. The issuance of additional shares of Series A Preferred Stock and preferred stock that would rank on parity with the Series A Preferred Stock could have the effect of reducing the amounts available to the current holders of our Series A Preferred Stock upon our liquidation or dissolution or the winding up of our affairs. It also may reduce dividend payments to the current holders of the Series A Preferred Stock if we do not have sufficient funds to pay dividends on all Series A Preferred Stock outstanding and other classes of stock with equal priority with respect to dividends.

In addition, although holders of Series A Preferred Stock are entitled to limited voting rights with respect to such matters, the Series A Preferred Stock will vote separately as a class along with the holders of all other classes or series of our equity securities we may issue upon which similar voting rights have been conferred and are exercisable and which are entitled to vote as a class with the Series A Preferred Stock. As a result, the voting rights of holders of Series A Preferred Stock may be significantly diluted, and the holders of such other series of preferred stock that we may issue may be able to control or significantly influence the outcome of any vote.

Future issuances and sales of preferred stock ranking on parity with the Series A Preferred Stock, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Series A Preferred Stock and our common stock to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

Holders of Series A Preferred Stock have extremely limited voting rights.

Voting rights as a holder of Series A Preferred Stock is limited. Our shares of common stock are the only class of our securities that carry full voting rights. Voting rights for holders of Series A Preferred Stock exist primarily with respect to the ability to elect, voting together with the holders of any other classes or series of our equity securities we may issue upon which similar voting rights have been conferred and are exercisable and which are entitled to vote as a class with the Series A Preferred Stock, two additional directors to our board of directors, subject to certain limitations, in the event that a “Listing Event” (defined below) occurs or if we do not pay dividends on the Series A Preferred Stock for any monthly dividend period within a quarterly period for a total of six (6) consecutive or non-consecutive quarterly periods, and with respect to voting on amendments to our restated articles of incorporation, as amended, or certificate of determination relating to the Series A Preferred Stock that materially and adversely affect the rights of the holders of Series A Preferred Stock or authorize, increase or create additional classes or series of our shares that are senior to the Series A Preferred Stock. A “Listing Event” means, with respect to the Series A Preferred Stock, if that class of stock is not listed on certain specified national stock exchanges (including the New York Stock Exchange, NYSE MKT or NASDAQ) for 180 or more consecutive days. Other than the limited circumstances described in this report, holders of Series A Preferred Stock do not have any voting rights.
 
 
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The Series A Preferred Stock is a relatively new issue of securities and has only a limited trading market, which may negatively affect its value and the ability to transfer and sell shares.

The Series A Preferred Stock is a relatively new issue of securities with only a limited trading market. The volume of trades of shares of the Series A Preferred Stock on the NYSE MKT is often low, and an active trading market on the NYSE MKT for the Series A Preferred Stock may not be maintained in the future and may not provide adequate liquidity. The liquidity of any market for the Series A Preferred Stock that may exist now or in the future will depend on a number of factors, including prevailing interest rates, the dividend rate on our common stock, our financial condition and operating results, the number of holders of the Series A Preferred Stock, the market for similar securities and the interest of securities dealers in making a market in the Series A Preferred Stock. As a result, the ability to transfer or sell the Series A Preferred Stock could be adversely affected.

If the Series A Preferred Stock or our common stock is delisted, the ability to transfer or sell shares of the Series A Preferred Stock may be limited, and the market value of the Series A Preferred Stock will likely be materially adversely affected.

Other than in connection with a Change of Control, the Series A Preferred Stock does not contain provisions that are intended to protect shareholders if our common stock is delisted from the NYSE MKT. Since the Series A Preferred Stock has no stated maturity date, shareholders may be forced to hold their shares of the Series A Preferred Stock and receive stated dividends on the Series A Preferred Stock when, and if authorized by our board of directors and paid by us with no assurance as to ever receiving the liquidation value thereof. In addition, if our common stock is delisted from the NYSE MKT, it is likely that the Series A Preferred Stock will be delisted from the NYSE MKT as well. Accordingly, if the Series A Preferred Stock or our common stock is delisted from the NYSE MKT, the ability to transfer or sell shares of the Series A Preferred Stock may be limited and the market value of the Series A Preferred Stock will likely be materially adversely affected.

Item 1B.                      Unresolved Staff Comments.

None.

Item 2.                                Properties.

A description of our properties is included in Item 1. Business and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.

Item 3.                                Legal Proceedings.

A description of our legal proceedings is included in Part II, Item 8. Consolidated Financial Statements and Supplementary Data, Note 17 – Contingencies, and is incorporated herein by reference.

From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not currently involved in any legal proceedings, nor are we a party to any pending or threatened claims, that could reasonably be expected to have a material adverse effect on our financial condition or results of operations.
 
 
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Item 4.                                Mine Safety Disclosures.

Not applicable.
 
 
41

 

PART II

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

Our common stock has been listed for trading on the NYSE MKT under the symbol “YUMA” since September 11, 2014. Prior to that date, the common stock was traded on the NYSE MKT under the symbol “PDO”. The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock on the NYSE MKT.

   
Common Stock Price
   
High
   
Low
Quarter Ended
         
2014
           
March 31
  $ 7.15     $ 4.86  
June 30
  $ 6.30     $ 5.03  
September 30
  $ 5.92     $ 3.81  
December 31
  $ 4.28     $ 1.71  

2015
           
March 31
  $ 2.11     $ 1.01  
June 30
  $ 1.17     $ 0.49  
September 30
  $ 0.83     $ 0.30  
December 31
  $ 0.60     $ 0.13  

As of March 22, 2016, there were approximately 205 shareholders of record of our common stock. The actual number of holders of our common stock is greater than the number of record holders and includes shareholders who are beneficial owners, but whose shares are held in street name by brokers and nominees.

Dividends

We have not paid cash dividends on our common stock in the past two years and we do not anticipate that we will declare or pay dividends on our common stock in the foreseeable future. Payment of dividends, if any, is within the sole discretion of our board of directors and will depend, among other factors, upon our earnings, capital requirements and our operating and financial condition. In addition, under California law, we may not pay a dividend if, after giving effect, we would be unable to pay our debts as they become due in the usual course of business or if our total assets would be less than the sum of our total liabilities plus the amount that would be needed if we were to be dissolved at the time of the payment of the dividend to satisfy the preferential rights upon dissolution of shareholders whose preferential rights were superior to those receiving the dividend. In addition, our credit agreement does not permit us to pay dividends on our common stock.
 
 
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Item 6.                                Selected Financial Data.

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this Item.

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

The following discussion is intended to assist in understanding our results of operations and our current financial condition.  Our consolidated financial statements and the accompanying notes included elsewhere in this report contain additional information that should be referred to when reviewing this material.

The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, joint ventures and dispositions, uncertainties in estimating proved reserves and forecasting production results, potential failure to achieve production from development projects, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital and financial markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements” and Item 1A. “Risk Factors.”
 
Restatement Background
As discussed in the Explanatory Note to this Form 10-K/A and Note 26 - Restatement of Previously Issued Financial Statements, we are restating (i) our consolidated balance sheets as of December 31, 2015 and 2014, (ii) our consolidated statements of operations, consolidated statements of comprehensive income (loss), consolidated statements of changes in equity and consolidated statements of cash flows for the years ended December 31, 2015, 2014 and 2013 and (iii) our unaudited quarterly financial information for the quarters ended March 31, 2014 through December 31, 2015 due to non-cash errors in the computation of our income tax provision and the recording of our deferred taxes related to our asset retirement obligations, our stock based compensation, our allocation of the purchase price in the Pyramid merger and resultant amount of goodwill, the tax amortization of that goodwill, the tax treatment of expenses related to the Pyramid merger, the incorrect roll forward of the historic net operating losses and the difference in the book and tax basis in our properties. As a result, our income tax provision and the net amount of our deferred tax liability were restated for the years ended December 31, 2015, 2014 and 2013 and the applicable quarterly periods in 2015 and 2014. Specifically, on May 11, 2016 we determined that subsequent to the filing of our Annual Report on Form 10-K for the year ended December 31, 2015, there were non-cash errors in the Company’s calculation of its income tax provision, its deferred tax liability and goodwill as of December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013. The net effect of correcting all of these non-cash errors resulted in a cumulative decrease in the Company’s deferred tax liability as of December 31, 2015 of $5,379,806 to a deferred tax liability balance at December 31, 2015 as restated of $1,417,364. These adjustments related to the Company’s calculation of deferred tax assets and liabilities primarily relating to the tax effects of asset retirement obligations, stock based compensation, merger related expenses and the Company’s purchase accounting and goodwill determination related to the Pyramid merger.  Specifically, we recognized an adjustment to the goodwill recorded in 2014 and subsequently written off in the second Quarter of 2015 of $422,480, which changed the reported goodwill carrying value from $5,349,988 to $4,927,508 at December 31, 2014.
 
As a result, the Company’s management, the Audit Committee and the Board of Directors determined after consideration of the relevant facts and circumstances, that our consolidated balance sheets as of December 31, 2015 and 2014, (ii) our consolidated statements of operations, consolidated statements of comprehensive income (loss), consolidated statements of changes in equity and consolidated statements of cash flows for the years ended December 31, 2015, 2014 and 2013 and (iii) our unaudited quarterly financial information for the quarters ended March 31, 2014 through December 31, 2015 should be restated, and that such financial statements previously filed with the Securities and Exchange Commission should no longer be relied upon.
 
In addition, Management evaluated the effect of the restatements on our prior conclusions regarding the effectiveness of the Company’s internal control over financial reporting and disclosure controls and procedures as of December 31, 2015. In connection therewith, management concluded that the Company did not maintain effective controls over the accuracy and presentation of the accounting for the Company’s income taxes, including income tax provisions and related deferred tax assets and liabilities. The Company identified both the errors and this material weakness and has taken action to remediate its procedures and controls, including hiring an internationally known accounting firm as our new tax consultants to assist management with its preparation of these items, and in addition, we intend to hire additional accounting personnel. Additionally, we are in the process of implementing a more robust review of our accounting of deferred taxes, and increasing the supervision and monitoring of the financial reporting processes related to this material weakness.  Nevertheless, the Company may continue to report the above material weakness while sufficient testing of newly established procedures and controls occurs.
 
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Please refer to Note 26 – Restatement of Previously Issued Financial Statements in the Notes to the Consolidated Financial Statements for the quarterly impact of the Restatement to the consolidated financial statements.

Overview

We are a Houston-based oil and gas company focused on the acquisition, development, and exploration for conventional and unconventional oil and natural gas resources in the U.S. Gulf Coast and California. We have employed a 3-D seismic-based strategy to build a multi-year inventory of development and exploration prospects. Our current operations are focused on onshore central and southern Louisiana, where we are targeting the Austin Chalk, Tuscaloosa, Wilcox, Frio, Marg Tex and Hackberry formations. In addition, we have a non-operated position in the Bakken Shale in North Dakota and operated positions in Kern and Santa Barbara Counties in California.

Recent developments

The prices of crude oil and natural gas have declined dramatically since mid-year 2014, having recently reached multiyear lows, as a result of robust supply growth, weakening demand in emerging markets, and OPEC’s decision to continue to produce at current levels.  These market dynamics have led many to conclude that commodity prices are likely to remain lower for a prolonged period.  In response to these developments, among other things, we have reduced our spending and looked to enter into a merger with Davis Petroleum Acquisition Corp. to increase our liquidity and improve our financial position (see description of the merger in Part II, Item 8. Notes to the Consolidated Financial Statements, Note 24 – Subsequent Events).  In addition, we are continuing to actively explore and evaluate various strategic alternatives, including asset sales, to reduce the level of our debt and lower our future cash interest obligations.  We believe that a reduction in our debt and cash interest obligations on a per barrel basis is needed to improve our financial position and flexibility and to position us to take advantage of opportunities that may arise out of the current industry downturn.

Reserves and non-cash full cost ceiling impairment

Our results of operations are heavily influenced by oil and natural gas prices, which have significantly declined and have remained low during the last year. These oil and natural gas price fluctuations are caused by changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the economic viability of and our ability to fund drilling projects, as well as the economic valuation and economic recovery of oil and natural gas reserves.
 
 
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As discussed previously in this report, during 2015 commodity prices for crude oil and natural gas experienced sharp declines, and this downward trend has accelerated further into the first quarter of 2016, with crude oil prices reaching a twelve-year low in February 2016. We have significantly reduced our capital budget for 2016. In addition, we have purposely significantly reduced the portion of our reserves that have historically been categorized as “proved undeveloped” or “PUD,” and have adjusted our drilling schedule and PUD bookings due to the current economic price environment and our financial condition.  We have focused on our efforts to develop our acreage in the most efficient manner possible and determine which potential locations will be most profitable.  Although we believe that we have a plan to develop our reserves, the current environment and the industry’s access to the capital markets may affect our ability to execute this plan.

NSAI, our independent reserve engineers, estimated 100% of our proved reserves as of December 31, 2015 and 2014. As of December 31, 2015, we had 13,261 MBoe of estimated proved reserves as compared to 19,888 MBoe of estimated proved reserves as of December 31, 2014. For prices used to value our reserves, See Part II, Item 8. Notes to the Consolidated Financial Statements, Note 25 – Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited).

Potential future low commodity price impact on our development plans, reserves and full cost impairment

Oil and natural gas prices have remained low in the first quarter of 2016. If prices remain at or below the current low levels, subject to numerous factors and inherent limitations, and all other factors remain constant, we may incur a non-cash full cost impairment during 2016, which will have an adverse effect on our results of operations.

There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. In addition to unknown future commodity prices, other uncertainties include (i) changes in drilling and completion costs, (ii) changes in oilfield service costs, (iii) production results, (iv) our ability, in a low price environment, to strategically drill the most economic locations in our targets, (v) income tax impacts, (vi) potential recognition of additional proved undeveloped reserves, (vii) any potential value added to our proved reserves when testing recoverability from drilling unbooked locations and (viii) the inherent significant volatility in the commodity prices for oil and natural gas recently exemplified by the large changes in recent months.

Each of the above factors is evaluated on a quarterly basis and if there is a material change in any factor it is incorporated into our internal reserve estimation utilized in our quarterly accounting estimates. We use our internal reserve estimates to evaluate, also on a quarterly basis, the reasonableness of our reserve development plans for our reported reserves. Changes in circumstance, including commodity pricing, economic factors and the other uncertainties described above may lead to changes in our reserve development plans.

We have set forth below a calculation of a potential future reduction of our proved reserves. Such implied impairment and decrease in reserves should not be interpreted to be indicative of our development plan or of our actual future results. Each of the uncertainties noted above has been evaluated for material known trends to be potentially included in the estimation of possible first-quarter effects. Based on such review, we determined that the impact of decreased commodity prices, changes to our reserves and future production due to expiring leases, and the roll-off of our estimated production are the only significant known variables in the following scenario.

Both our hypothetical first-quarter 2016 full cost ceiling calculation and our hypothetical reserves estimates have been prepared by substituting (i) $46.26 per barrel for oil, and (ii) $2.40 per MMBtu for natural gas (the “Pro Forma Prices”) for the respective realized prices as of March 31, 2016. Changes to our reserves and future production due to expiring leases were made as well as changing the effective date of the evaluation from December 31, 2015 to March 31, 2016 to account for the roll-off of the estimated production and reduction in reserves.  All other inputs and assumptions have been held constant. Accordingly, this estimation accounts for the impact of more current commodity prices on the first-quarter 2016 realized prices that will be utilized in our full cost ceiling calculation and our reserves estimate. The Pro Forma Prices use a slightly modified realized price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for oil, natural gas liquids and natural gas on the first day of the month for the 12 months ended March 1, 2016.  Using this methodology, the estimated implied impact to our December 31, 2015 reserves of 13,261 MBoe would be a reduction of 3,478 MBoe.  However, this estimated reduction would not result in a first quarter ceiling test impairment in 2016.  We believe that substituting the Pro Forma Prices into our December 31, 2015 internal reserve estimates may help provide users with an understanding of the potential first-quarter price impact on our March 31, 2016 full cost ceiling test and in preparing our year-end reserve estimates.
 
 
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Mergers and acquisitions

On February 10, 2016, the Company and privately held Davis Petroleum Acquisition Corp. (“Davis”) entered into a definitive merger agreement for an all-stock transaction. Upon completion of the transaction, we will reincorporate in Delaware, implement a one-for-ten reverse split of our common stock, and convert each share of our existing Series A Preferred Stock into 35 shares of common stock prior to giving effect for the reverse split (3.5 shares post reverse split).  Following these actions, we will issue additional shares of common stock in an amount sufficient to result in approximately 61.1% of the common stock being owned by the current common stockholders of Davis.  In addition, we will issue approximately 3.3 million shares of a new Series D preferred stock to existing Davis preferred stockholders, which  is estimated to have a conversion price of approximately $5.70 per share, after giving effect for the reverse split.  The Series D preferred stock is estimated to have an aggregate liquidation preference of approximately $19.0 million at closing, and will be paid dividends in the form of additional shares of Series D preferred stock at a rate of 7% per annum. Upon closing, there will be an aggregate of approximately 23.7 million shares of our common stock outstanding (after giving effect to the reverse stock split and conversion of Series A Preferred Stock to common stock). The transaction is expected to qualify as a tax-deferred reorganization under Section 368(a) of the Code.

Results of Operations
 
Production

The following table presents the net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 31, 2015, 2014 and 2013, and the average sales price per unit sold.

   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
Production volumes:
 
 
   
 
       
Crude oil and condensate (Bbl)
    247,177       231,816       184,349  
Natural gas (Mcf)
    1,993,842       2,714,586       1,580,468  
Natural gas liquids (Bbl)
    74,511       97,783       51,875  
   Total (Boe) (1)
    653,995       782,030       499,635  
                         
Average prices realized:
                       
Excluding commodity derivatives:
                       
Crude oil and condensate (per Bbl)
  $ 48.07     $ 93.98     $ 104.26  
Natural gas (per Mcf)
  $ 2.60     $ 4.62     $ 3.83  
Natural gas liquids (per Bbl)
  $ 18.89     $ 38.44     $ 40.17  
Including commodity derivatives:
                       
Crude oil and condensate (per Bbl)
  $ 65.20     $ 101.98     $ 104.39  
Natural gas (per Mcf)
  $ 3.00     $ 5.19     $ 3.71  
Natural gas liquids (per Bbl)
  $ 18.89     $ 38.44     $ 40.17  
 
(1)  
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).
 
 
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Revenues

The following table presents our revenues for the years ended December 31, 2015, 2014 and 2013.

  
 
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
Sales of natural gas and crude oil:
                 
Crude oil and condensate
  $ 11,881,626     $ 21,785,636     $ 19,220,185  
Natural gas
    5,181,715       12,542,671       6,049,500  
Natural gas liquids
    1,407,512       3,758,875       2,083,905  
Gain/(loss) on commodity derivatives
    5,038,826       3,398,518       (159,810 )
Gas marketing
    209,731       572,210       881,823  
Total revenues
  $ 23,719,410     $ 42,057,910     $ 28,075,603  
 
Sale of Crude Oil and Condensate
 
Crude oil and condensate are sold through month-to-month evergreen contracts. The price for Louisiana production is tied to an index or a weighted monthly average of posted prices with certain adjustments for gravity, Basic Sediment and Water (“BS&W”) and transportation. Generally, the index or posting is based on West Texas Intermediate (“WTI”) and adjusted to Light Louisiana Sweet (“LLS”) or Heavy Louisiana Sweet (“HLS”). For the years ended December 31, 2015, 2014 and 2013, LLS postings averaged $3.48, $3.02 and $9.58 over WTI, respectively.  Pricing for our California properties is based on an average of specified posted prices, adjusted for gravity, transportation, and for one field, a market differential.

Crude oil volumes sold were 6.6% higher for the year ended December 31, 2015 than the crude oil volumes sold during the year ended December 31, 2014.  This increase was a result of increased production from Livingston and Main Pass 4 wells and a full year of production from our California assets, partially offset by declines from Masters Creek and La Posada properties.  In the Livingston area fields, we focused on optimizing the artificial lift systems and reducing downtime and workovers.  At Main Pass 4, we re-engineered the facilities to increase our water handling and disposal capacity and to improve run-times. Realized crude oil prices experienced a 48.9% decrease from the year ended December 31, 2014 to the year ended December 31, 2015.

Crude oil volumes sold increased by 25.7% for the year ended December 31, 2014 compared to the year ended December 31, 2013. New production came from two wells and the newly acquired Pyramid wells, and was further enhanced by increased sales on five wells after successful workover operations.  Some reductions were due to the shut-in of two wells for salt water disposal well work and declining production from two other wells and the Bakken wells in North Dakota. Realized crude oil prices experienced a 9.9% decrease from the year ended December 31, 2013 to the year ended December 31, 2014.

Sale of Natural Gas and Natural Gas Liquids
 
Our natural gas is sold under multi-year contracts with pricing tied to either first of the month index or a monthly weighted average of purchaser prices received. Natural gas liquids are also sold under multi-year contracts usually tied to the related natural gas contract. Pricing is based on published prices for each product or a monthly weighted average of purchaser prices received.

For the year ended December 31, 2015 compared to the year ended December 31, 2014, we experienced a 26.6% decrease in natural gas volumes sold and a 23.8% decrease in natural gas liquids sold primarily due to production declines in the Bayou Hebert (La Posada) field, which were partially offset by new production from our Talbot 23-1 well. During the same period, realized natural gas prices decreased by 43.7% and realized natural gas liquids prices decreased by 50.9%.

For the year ended December 31, 2014 compared to the year ended December 31, 2013, a 71.8% increase in natural gas volumes sold was primarily due to increased production from the Crosby 12-1 and the net revenue increase at La Posada, partially offset by production declines from the Broussard No. 2 and Thibodeaux No. 1.  These increases in natural gas sales led to increases in natural gas liquids sales of 88.5%.  During the same period, realized natural gas prices increased by 20.6% and realized natural gas liquids prices decreased by 4.3%.
 
 
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Gas Marketing
 
Gas marketing sales are natural gas volumes purchased from certain of our operated wells and the aggregated volumes sold with a mark-up of $.03 per MMBtu. Our wholly owned subsidiary, Texas Southeastern Gas Marketing Company (“Marketing”), purchases and sells natural gas on our behalf and on behalf of our working interest partners. In early 2016, we discontinued Marketing due to a lack of volumes and the associated costs of running the company (see Part II, Item 8. Notes to the Consolidated Financial Statements, Note 24 – Subsequent Events).

Expenses

Lease Operating Expenses
 
Our lease operating expenses (“LOE”) and LOE per Boe for the years ended December 31, 2015, 2014 and 2013, are set forth below:

   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
Lease operating expenses
  $ 7,531,846     $ 7,350,237     $ 5,265,794  
Severance, ad valorem taxes and marketing
    3,869,463       5,466,488       4,050,570  
     Total LOE
  $ 11,401,309     $ 12,816,725     $ 9,316,364  
                         
LOE per Boe
  $ 17.43     $ 16.39     $ 18.65  
LOE per Boe without severance, ad valorem taxes and marketing
  $ 11.52     $ 9.40     $ 10.54  
 
LOE includes all costs incurred to operate wells and related facilities, both operated and non-operated. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE also includes severance taxes, product marketing and transportation fees, insurance, ad valorem taxes and operating agreement allocable overhead. LOE excludes costs classified as re-engineering and workovers.

The 11.0% decrease in total LOE for the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily due to operating cost reduction initiatives implemented in our Greater Masters Creek Area, Livingston, and California.  LOE per barrel of oil equivalent increased by 6.3% for the same period generally due to the lower natural gas and natural gas liquids sales when compared to the prior year.

The 37.6% increase in LOE for the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to maintenance projects, an increased working interest for the La Posada wells due to achieving payout, and LOE for the Crosby 12-1 well and the Pyramid properties acquired.  LOE per barrel of oil equivalent decreased by 12.1% for the same period generally due to increased sales volumes.

Re-engineering and Workovers

Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations.

Workover expenses for the years ended December 31, 2015, 2014 and 2013 totaled $555,539, $3,084,972, and $2,521,707, respectively. Workover expenses decreased by 82.0% in the year ended December 31, 2015 compared to the year ended December 31, 2014 primarily because of the high workover expenses incurred in 2014 to restore salt water disposal at Gardner Island (Main Pass 4) and Raccoon Island (Main Pass 2).  Additionally, in 2015 the artificial lift optimization projects completed in Livingston, the re-engineered facilities installed at Main Pass 4, and the cost reduction initiatives at Masters Creek and in California led to fewer workovers, down time, and less activity overall. Workover expenses increased by 22.3% in the year ended December 31, 2014 compared to the same period in 2013 due to work on the Gardner Island and Raccoon Island salt water disposal wells.  Additionally, LOE per Boe, including re-engineering and workovers, for the years ended December 31, 2015, 2014 and 2013 totaled $18.28, $20.33 and $23.69, respectively.  All re-engineering work performed in 2015 was completed prior to July 2015.  Additional work planned for 2015 was deferred due to commodity prices.
 
 
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General and Administrative Expenses
 
Our general and administrative (“G&A”) expenses for the years ended December 31, 2015, 2014 and 2013, are summarized as follows:

   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
General and administrative:
             
 
 
Stock-based compensation
  $ 3,086,209     $ 4,293,855     $ 589,164  
Capitalized
    (796,898 )     (905,534 )     (137,106 )
   Net stock-based compensation
    2,289,311       3,388,321       452,058  
                         
Other
    9,727,419       10,692,639       7,186,069  
Capitalized
    (2,293,115 )     (2,536,562 )     (2,649,563 )
    Net other
    7,434,304       8,156,077       4,536,506  
                         
Net general and administrative expenses
  $ 9,723,615     $ 11,544,398     $ 4,988,564  
 
G&A expenses primarily consist of overhead expenses, employee remuneration and professional and consulting fees. We capitalize certain G&A expenditures when they satisfy the criteria for capitalization under GAAP as relating to oil and natural gas exploration activities following the full cost method of accounting.
 
For the year ended December 31, 2015, net G&A expenses were $1,820,783 (15.8%) less than the amount for the prior year ended December 31, 2014. The reduction in G&A expenses was primarily attributed to a decrease in stock-based compensation, along with higher costs in 2014 for professional fees associated with the merger and costs to explore other public listing options.  Stock-based compensation net of amounts capitalized totaled $2,289,311 and $3,388,321 for fiscal years 2015 and 2014, respectively.  Non-recurring professional costs related to the merger and costs to explore other public listing options totaled $113,997 and $2,935,536 in fiscal years 2015 and 2014, respectively.   Also included in 2015 G&A costs were $406,556 in non-recurring severance benefits for several employees terminated at year-end.

For the year ended December 31, 2014, net G&A expenses were $6,555,834 (131.4%) over the amount for the prior year ended December 31, 2013. The increases were due in large part to the initial amortization of restricted stock awards at the time of the merger, triggered as a result of the condition of the Company going public.  This stock-based compensation, net of amounts capitalized, totaled $3,388,321 and $452,058 for fiscal years 2014 and 2013, respectively.  Additionally, non-recurring professional costs associated with the merger and costs to explore other public listing options totaled $2,935,536 and $24,592 in fiscal years 2014 and 2013, respectively.  Excluding these costs for prior stock-based compensation and the merger, along with Pyramid’s 2014 G&A costs of $127,534, net G&A expenses for 2014 were $581,093, or 12.9%, over 2013.  This increase was primarily the result of five (net) employee additions in 2014.
 
Depreciation, Depletion and Amortization

Our depreciation, depletion and amortization (“DD&A”) for the years ended December 31, 2015, 2014 and 2013, is summarized as follows:

   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
DD&A
  $ 13,651,207     $ 19,664,991     $ 12,077,368  
                         
DD&A per Boe
  $ 20.87     $ 25.15     $ 24.17  
 
 
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DD&A per Boe decreased by 17.0% for the year ended December 31, 2015 compared to the year ended December 31, 2014. The decrease resulted primarily from the reduction of the net quantities of natural gas and natural gas liquids sold by us and the reduction of the proved reserves associated with the reclassification of proved undeveloped reserves to non-proved. The net quantities of oil, natural gas and natural gas liquids produced and sold by us increased by 56.5% for the year ended December 31, 2014 compared to the year ended December 31, 2013.  This increase in production was the primary factor for the 4.1% increase in DD&A per Boe in 2014 over 2013.  See “Production” above for the volumes of oil, natural gas and natural gas liquids production.

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDA

The following table reconciles reported net income to Adjusted EBITDA for the periods indicated:

   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
      (As Restated)       (As Restated)       (As Restated)  
Net Income (loss)
  $ (14,839,840 )   $ (20,842,657 )   $ (28,588,894 )
Depreciation, depletion & amortization of property and equipment
    13,651,207       19,664,991       12,077,368  
Interest expense, net of interest income and amounts capitalized
    436,836       302,568       560,340  
Income tax benefit
    (3,725,757 )     (1,936,347 )     (1,380,937 )
Goodwill impairment
    4,927,508       -       -  
Stock-based compensation net of capitalized cost
    2,289,311       3,388,321       452,058  
Unrealized (gains) losses on commodity derivatives
    949,967       (4,724,985 )     231,886  
Accretion of asset retirement obligation
    604,538       604,511       668,497  
Costs to obtain a public listing
    -       2,935,536       24,592  
Increase in value of preferred stock derivative liability
    -       15,676,842       26,258,559  
Bank mandated commodity derivative novation cost
    -       -       175,000  
Amortization of benefit from commodity derivatives sold
    -       (93,750 )     (72,600 )
Adjusted EBITDA
  $ 4,293,770     $ 14,975,030     $ 10,405,869  

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis.  It is also used to assess our ability to incur and service debt and fund capital expenditures.

 Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flow provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.  Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. Adjusted EBITDA for the year ended December 31, 2015 decreased from 2014 by $10,681,260 (71.3%). Adjusted EBITDA for the year ended December 31, 2014 increased from 2013 by $4,569,161 (43.9%).

Interest Expense
 
Our interest expense for the years ended December 31, 2015, 2014 and 2013, is summarized as follows:

   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
Interest expense
  $ 1,439,895     $ 1,385,550     $ 1,599,492  
Interest capitalized
    (983,472 )     (1,059,350 )     (1,031,816 )
Net
  $ 456,423     $ 326,200     $ 567,676  
                         
Bank debt
  $ 29,800,000     $ 22,900,000     $ 31,215,000  
 
Interest expense increased $54,345 for the year ended December 31, 2015 over the same period in 2014 as a result of increased borrowings during 2015.  Capitalized interest decreased $75,878 for the year ended December 31, 2015 from the same period in 2014, driven by a decrease in our unevaluated properties since 2014, which is the basis of our capitalized interest calculation.
 
 
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Interest expense decreased $213,942 for the year ended December 31, 2014 from the same period in 2013 as a result of debt decreasing in fiscal year 2014 when net proceeds from the sale of the issuance of the Series A Preferred Stock were used to pay down debt by $10.4 million during October 2014. Capitalized interest increased $27,534 for the year ended December 31, 2014 over the same period in 2013 due to an increase in the value of oil and gas properties not subject to amortization.

For a more complete narrative of interest expense, refer to Note 13 – Debt and Interest Expense in the Notes to Consolidated Financial Statements included in this report.
 
Income Tax Expense
 
The following summarizes our income tax expense (benefit) and effective tax rates for the years ended December 31, 2015, 2014 and 2013:
 
   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
   
(As Restated)
   
(As Restated)
   
(As Restated)
 
Consolidated net income (loss) before income taxes
  $ (18,565,597 )   $ (22,779,004 )   $ (29,969,831 )
Income tax expense (benefit)
    (3,725,757 )     (1,936,347 )     (1,380,937 )
Effective tax rate
    20.07 %     8.50 %     4.61 %
 
Additionally, differences between the U.S. federal statutory rate of 34 % and our effective tax rates are due to the tax effects of the excess of book carrying value over the tax basis in the full cost pool and the net operating loss carryforwards for each period. No benefit has been recognized for nondeductible expenses. Refer to Note 16 – Income Taxes in the Notes to Consolidated Financial Statements included in this report.

Liquidity and Capital Resources
 
Our primary and potential sources of liquidity include cash on hand, cash from operating activities, borrowings under our revolving credit facility, proceeds from the sales of assets, and potential proceeds from capital market transactions, including the sale of debt and equity securities.  Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production.  Our business plan contemplates the potential merger with Davis Petroleum Acquisitions Corp., which we anticipate will help us with our liquidity and potentially put us in compliance with our credit facility.  While we anticipate the completion of this merger, we are subject to a number of factors that are beyond our control, including commodity prices, our bank’s determination of our borrowing base which could impact the merger, production declines, and other factors that could affect our liquidity and ability to continue as a going concern.  Our 2016 business plan includes the capital to drill two wells, a Greater Masters Creek Field Area proved undeveloped location and another proved undeveloped location in Santa Barbara County, California in the Cat Canyon field once the necessary permits are approved.  Other capital investments are also planned for both operated and non-operated recompletions, artificial lift upgrades, and capitalized workovers.

Cash Flows
 
Our net increase (decrease) in cash for the years ended December, 31, 2015, 2014 and 2013, is summarized as follows:

   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
Cash flows provided by (used in) operating activities
  $ (1,370,144 )   $ 24,466,300     $ 14,912,903  
Cash flows used in investing activities
    (12,311,157 )     (18,088,363 )     (27,253,041 )
Cash flows provided by (used in) financing activities
    7,478,170       985,874       11,249,627  
Net increase (decrease) in cash
  $ (6,203,131 )   $ 7,363,811     $ (1,090,511 )
 
 
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Cash Flows From Operating Activities
 
Cash flows from operations for the year ended December 31, 2015 decreased by $25,836,444, or 106%, over fiscal year 2014 primarily due to changes in working capital, decreased revenues due to low commodity prices, and decreased production.

Cash flows from operations for the year ended December 31, 2014 increased by $9,553,397, or 64%, over fiscal year 2013 primarily due to increased working interest in the La Posada field, new production from the Bertha 8-3 and the Nettles 39-1, the addition of the California production after the merger, and increased production at the Crosby 12-1 and Quinn 13-1 wells. These increases were somewhat mitigated by higher lease operating expenses associated with increased production.

Cash Flows From Investing Activities

During the year ended December 31, 2015, we had a total of $10,126,307 in oil and natural gas investing activities.  Of that, $4,366,695 was related to acquisitions of acreage and new properties, which included capitalized G&A and interest costs of $3.2 million, and approximately $0.77 million of acquisition costs for additional interest in our Livingston and Branville Bay assets.  Drilling and completion activity during the period totaled $4,219,210.  The majority of drilling and completion activity in 2015 is attributed to the drilling and completion of the Talbot 23-1 well for $3,181,382, and the completion of  the Blackwell 39-1 and the Crosby 14-1 wells for $386,403 and $361,347, respectively.  Recompletions, workovers and P&A activity totaled $1,540,402.  Notable projects include installing a gas lift system in a Masters Creek well for $485,134, installing electrical submersible pumps (ESP) in two Livingston Parish oil wells for $401,200, and re-engineering production and SWD facilities at Main Pass 4 for $176,825.

During the year ended December 31, 2014, the Greater Masters Creek Field Area accounted for $18,225,766 of our total oil and natural gas investing activities. Of that, $16,449,165 was spent to drill and complete the Crosby 14-1 well and its related salt water disposal well. The remaining $1,776,601 was spent on lease-related activities and preliminary costs for the next wells to be drilled in the field.  At the Livingston 3-D Project, $1,157,071 was spent to drill and complete the Nettles 39-1 well, along with $1,047,656 to drill the Blackwell 39-1, which was completed in the first quarter of 2015.  Lease-related costs totaled $484,583. The Talbot 23-1 well in the Amazon 3-D Project was spudded in early January 2015, and we incurred $364,411 in preliminary costs in 2014.  Lease-related costs totaled $732,899. Additionally, $816,970 was spent evaluating and identifying development opportunities for our new producing properties in California. A net credit of $667,338 for insurance recovery on the Grief Bros. No. 1 created a credit balance for recompletions, capital workovers and P&A for the period ended December 31, 2014. During 2013, we realized proceeds from the sale of interests in our projects and the sale of a salt water disposal well of $882,666.
 
 
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Cash Flows From Financing Activities
 
 Our cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices. Although we seek to mitigate this risk by hedging future crude oil and natural gas production through 2017, a significant deterioration in commodity prices negatively impacts revenues, earnings, cash flows, capital spending, and our liquidity. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile or as impactful as commodity prices in the short-term.

We expect to finance future acquisition, development and exploration activities through available working capital, cash flows from operating activities, sale of non-strategic assets, and the possible issuance of additional equity/debt securities. In addition, we may slow or accelerate our development of existing reserves to more closely match our projected cash flows.

On December 30, 2015, we entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment to the credit agreement which provided for a $29.8 million conforming borrowing base, which will be automatically reduced to $20.0 million on May 31, 2016 unless otherwise reduced by or to a different number by the lenders under the credit agreement.

During the year ended December 31, 2015, we sold 46,857 shares of our Series A Preferred Stock for aggregate net proceeds of $870,386, after deducting underwriting discounts and offering expenses, and 1,347,458 shares of our common stock for aggregate gross proceeds of $1,363,160, after deducting underwriting discounts and offering expenses under our sales agreement. We used the net proceeds from the offering to fund our capital expenditures and to repay our debt.

At December 31, 2015, we had a $29.8 million conforming borrowing base with $29.8 million advanced, leaving no available borrowing capacity. The borrowing base will be reduced to $20.0 on May 31, 2016.

   
Years Ended December 31,
 
   
2015
   
2014
   
2013
 
 Credit facility:
                 
 Balances outstanding, beginning of year
  $ 22,900,000     $ 31,215,000     $ 17,875,000  
Activity
    6,900,000       (8,315,000 )     13,340,000  
 Balances outstanding, end of period
  $ 29,800,000     $ 22,900,000     $ 31,215,000  
 
Other than the credit facility, we had debt of $263,635 and $282,843 at December 31, 2015 and December 31, 2014, respectively, from installment loans financing oil and natural gas property insurance premiums.  We had a cash balance of $5,355,191 at December 31, 2015.

We were in breach of the financial covenant in our credit agreement related to the maximum permitted ratio of funded debt to EBITDA for the fiscal quarters ended September 30, 2015 and December 31, 2015 as well as our EBITDA to interest expense covenant at December 31, 2015. We received a waiver of these breaches pursuant to an amendment to our credit agreement. See Part II, Item 8. Notes to the Consolidated Financial Statements, Note 3 – Liquidity Considerations.

Credit Facility

We have a credit facility with a syndicate of banks that, as of December 31, 2015, had a borrowing base of $29.8 million through May 31, 2016 and thereafter the borrowing base will automatically be reduced to $20.0 million unless otherwise reduced by or to a different amount by the lenders under the credit agreement, with borrowings of $29.8 million outstanding. The credit agreement governing our credit facility provides for interest-only payments until May 20, 2017, when the credit agreement matures and any outstanding borrowings are due. The borrowing base under our credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base.

Our obligations under the credit agreement are guaranteed by our subsidiaries and are secured by liens on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 85% of the proved developed reserve value and at least 50% of the proved undeveloped reserve value of the oil and natural gas properties included in the determination of the borrowing base.
 
 
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Amounts borrowed under the credit agreement bear interest at either (a) the LIBOR rate plus 2.25% to 3.75% or (b) the prime rate plus 1.25% to 2.75%, depending on the amount borrowed under the credit facility. The credit facility contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness, create liens on assets, sell certain assets and engage in certain transactions with affiliates. Additionally, the credit agreement contains a covenant restricting the payment of dividends on preferred stock if there is less than ten percent availability on the borrowing base. See Part II, Item 8. Notes to the Consolidated Financial Statements, Note 3 – Liquidity Considerations and Note 13 – Debt and Interest Expense.

We are subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of EBITDA to Interest Expense (which includes dividends as defined in the credit agreement) of not less than 2.75 to 1.0; (2) a ratio of Funded Debt to EBITDA (as defined in the credit agreement) of not more than 4.0 to 1.0; and (3) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. As of September 30, 2015, we were not in compliance with the ratio of Funded Debt to EBITDA and received a waiver for compliance from our lenders. Further, the waiver also waived any failure to comply with the above financial covenants as of December 31, 2015, at which time both the funded debt to EBITDA and the EBITDA to interest expense ratios were not in compliance.  Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the amounts outstanding under the credit agreement are dependent on the timing of cash flows from operations, capital expenditures, acquisitions and dispositions of oil and natural gas properties and securities offerings.

Our credit facility also places restrictions on us and certain of our subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, payment of cash dividends on our Series A Preferred Stock, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

The credit agreement is subject to customary events of default, including in connection with a change in control. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).

Hedging Activities
 
Current Commodity Derivative Contracts
 
We seek to reduce our sensitivity to oil and natural gas price volatility and secure favorable debt financing terms by entering into commodity derivative transactions which may include fixed price swaps, price collars, puts, calls and other derivatives. We believe our hedging strategy should result in greater predictability of internally generated funds, which in turn can be dedicated to capital development projects and corporate obligations. 

Fair Market Value of Commodity Derivatives
 
   
December 31, 2015
   
December 31, 2014
 
   
Oil
   
Natural Gas
   
Oil
   
Natural Gas
 
Assets
                       
Current
  $ 2,393,032     $ 265,015     $ 1,851,542     $ 1,486,995  
Noncurrent
    1,049,661       20,880       1,006,845       396,264  
 
Assets and liabilities are netted within each commodity on the balance sheet as all contracts are with the same counterparty. For the balances without netting, refer to Part II, Item 8. Notes to the Consolidated Financial Statements, Note 9 – Commodity Derivative Instruments.
 
The fair market value of our commodity derivative contracts in place at December 31, 2015 and December 31, 2014 were net assets of $3,728,588 and $4,741,646, respectively. We sold all of our oil and natural gas options (while retaining swap contracts) in February 2015 for $4.03 million, accounting for the decrease in market value from December 31, 2014. New swaps and options contracts were concurrently initiated for the remainder of 2015 through 2017.
 
 
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See Part II, Item 8. Notes to the Consolidated Financial Statements, Note 9 – Commodity Derivative Instruments, for additional information on our commodity derivatives.

Hedging commodity prices for a portion of our production is a fundamental part of our corporate financial management. In implementing our hedging strategy we seek to:
 
● 
effectively manage cash flow to minimize price volatility and generate internal funds available for operations, capital development projects and additional acquisitions; and

● 
ensure our ability to support our exploration activities as well as administrative and debt service obligations.
 
Estimating the fair value of derivative instruments requires complex calculations, including the use of a discounted cash flow technique, estimates of risk and volatility, and subjective judgment in selecting an appropriate discount rate. In addition, the calculations use future market commodity prices which, although posted for trading purposes, are merely the market consensus of forecasted price trends. The results of the fair value calculation cannot be expected to represent exactly the fair value of our commodity derivatives. We currently obtain fair value positions from our counterparties and compare that value to the calculated value provided by our outside commodity derivative consultant. We believe that the practice of comparing the consultant’s value to that of our counterparties, who are specialized and knowledgeable in preparing these complex calculations, reduces our risk of error and approximates the fair value of the contracts, as the fair value obtained from our counterparties would be the cost to us to terminate a contract at that point in time.

Commitments and Contingencies
 
We had the following contractual obligations and commitments as of December 31, 2015:
 
   
Debt (1)
   
Asset for
Commodity
Derivatives (2)
   
Operating
Leases
   
Asset
Retirement
Obligations
 
2016
  $ 30,063,635     $ 2,658,047     $ 579,873     $ 70,000  
2017
    -       1,070,541       564,326       546,284  
2018
    -       -       2,264       3,691,016  
2019
    -       -       -       2,273,289  
2020
    -       -       -       60,330  
Thereafter
    -       -       -       2,149,579  
Totals
  $ 30,063,635     $ 3,728,588     $ 1,146,463     $ 8,790,498  
 
(1)
 
Does not include future commitment fees, interest expense or other fees because our credit agreement is a floating rate instrument, and we cannot determine with accuracy the timing of future loans, advances, repayments or future interest rates to be charged.
     
(2)
 
Represents the estimated future payments under our oil and natural gas derivative contracts based on the future market prices as of December 31, 2015. These amounts will change as oil and natural gas commodity prices change.
 
Off Balance Sheet Arrangements
 
We do not have any off balance sheet arrangements, special purpose entities, financing partnerships or guarantees (other than our guarantee of our wholly owned subsidiary’s credit facility).
 
 
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Critical Accounting Policies and Estimates
 
Critical accounting policies are defined as those that are reflective of significant judgments and uncertainties and that could potentially result in materially different results under different assumptions and conditions.  See Note 1 – Summary of Significant Accounting Policies in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this report, for a discussion of additional accounting policies and estimates made by management.

Accounting Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the U. S. (“GAAP”) requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.  Accounting policies are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.

Reserve Estimates

Our estimates of proved oil and natural gas reserves constitute those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal of such contracts is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. 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 natural 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 natural 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 regulation by governmental agencies, and assumptions governing future oil and natural 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 and therefore not includable in our reserve calculations. 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 natural gas properties and/or the rate of depletion of such oil and natural gas properties.

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

Full Cost Method of Accounting

We use the full cost method of accounting for our investments in oil and natural 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 dry hole costs, wells 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 natural 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 natural gas.
 
 
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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 natural 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 natural 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 natural gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling).  If capitalized costs exceed the full cost ceiling, the excess is an impairment charge to income and a write-down of oil and natural gas properties in the quarter in which the excess occurs.

Given the volatility of oil and natural gas prices, it is probable that our estimate of discounted future net cash flows from estimated proved oil and natural gas reserves will change in the near term.

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, currently available procedures and consultations with construction and engineering consultants.  Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.

Derivative Hedging Instruments

We seek to reduce our exposure to commodity price volatility by hedging a portion of our production through commodity derivative instruments.  The estimated fair values of our commodity derivative instruments are recorded in the Consolidated Balance Sheet.  The changes in the fair value of the derivative instruments are recorded in the Consolidated Statement of Operations and included in sales of natural gas and crude oil.

Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX discount rates and price movements.  The fair value of our commodity derivatives are calculated by our hedge counterparty and tested by an independent third party utilizing market-corroborated inputs that are observable over the term of the derivative contract.
 
 
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Derivatives Associated with Preferred Stock

We issued Series A Preferred Stock on July 1, 2011 and Series B Preferred Stock in July and August of 2012.  These shares of preferred stock had provisions with features of an option or derivative.  Therefore, each quarter that these shares were outstanding required that this derivative liability be marked to fair value with the resulting changes recorded on the Consolidated Statement of Operations as “Change in fair value of preferred stock derivative liability – Series A and Series B.”  Since we were not public at the time, this determination of fair value was performed with the use of a Monte Carlo option pricing model by an outside consulting firm using level 3 inputs, along with management estimates of the probability of various events.

Goodwill

We account for goodwill in accordance with ASC 350, Intangibles—Goodwill and Other (“ASC 350”). Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350 requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in impairment.  The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units.  We have one reporting unit.  Goodwill recorded on our financial statements is related to the merger with Pyramid in 2014.

Accounting Standards Update (“ASU”) No. 2011-08, Testing for Goodwill Impairment (“ASU 2011-08”), simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying value.  If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then the entity does not have to perform the two-step impairment test.  However, if the same conclusion is not reached, the entity is required to perform the first step of the two-step impairment test.  In this step, the fair value of the reporting unit is calculated and compared to the carrying value of the reporting unit.  If the carrying value exceeds the fair value, then the entity must perform the second step of the impairment test to measure the amount of impairment loss, if any.  ASU 2011-08 also allows a company to bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test. As a result of the application of the two-step process during the second quarter of 2015, the Company determined to write-off the entire goodwill associated with the Pyramid acquisition of $5.3 million.