Yuma Energy, Inc. - Annual Report: 2018 (Form 10-K)

 

 

    For the fiscal year ended December 31, 2018

 

    For the transition period from                          to                            .

 

(Exact name of registrant as specified in its charter)

 

DELAWARE (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, $0.001 par value per share		NYSE American

 

 

 

 

 

 

 

 

 

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐ (Do not check if a smaller reporting company)	Smaller reporting company	☒
		Emerging growth company	☐

 

 

 

 

 

 

 

 

TABLE OF CONTENTS

 

		Page
	Glossary of Selected Oil and Natural Gas Terms	1
	PART I
Item 1.	Business.	4
Item 1A.	Risk Factors.	24
Item 1B.	Unresolved Staff Comments.	42
Item 2.	Properties.	42
Item 3.	Legal Proceedings.	42
Item 4.	Mine Safety Disclosures.	45
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	46
Item 6.	Selected Financial Data.	46
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	47
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	59
Item 8.	Financial Statements and Supplementary Data.	59
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures.	59
Item 9A.	Controls and Procedures.	59
Item 9B.	Other Information.	60
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.	61
Item 11.	Executive Compensation.	61
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	61
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	61
Item 14.	Principal Accounting Fees and Services.	61
	PART IV
Item 15.	Exhibits, Financial Statement Schedules.	62
Item 16.	Form 10-K Summary.	64
	Signatures.	65

 

 

 

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:

 

 

 

 

 

 

 

 

 

 

 

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. You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. 

 

 

Glossary of Selected Oil and Natural Gas Terms

 

All defined terms under Rule 4-10(a) of Regulation S-X shall have their regulatory prescribed meanings when used in this report. As used in this document:

 

“3-D seismic” means an advanced technology method of detecting accumulation of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

 

“Basin” means a large depression on the earth’s surface in which sediments accumulate.

 

“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, in which six Mcf of natural gas equals one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas differs significantly from the price for a barrel of oil. A barrel of NGLs also differs significantly in price from a barrel of oil.

 

“Boe/d” means Boe per day.

 

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

 

“Development well” means a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

“Dry hole” means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

 

“Exploratory well” means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

 

“GAAP” (generally accepted accounting principles) is a collection of commonly-followed accounting rules and standards for financial reporting.

 

“Gross acres or gross wells” mean the total acres or wells, as the case may be, in which we have working interest.

 

“Horizontal drilling” means a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

 

“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.

 

“Net acres or net wells” means gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.

 

 “NGL” or “NGLs” means natural gas liquids, i.e. hydrocarbons removed as a liquid, such as ethane, propane and butane, which are expressed in barrels.

 

“NYMEX” means New York Mercantile Exchange.

 

“Oil” includes crude oil and condensate.

 

“Productive well” means a well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

 

“Proved area” means the part of a property to which proved reserves have been specifically attributed.

 

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

 

“Proved oil and natural gas reserves” means the estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

 

“Proved undeveloped reserves” means proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

 

“Realized price” means the cash market price less all expected quality, transportation and demand adjustments.

 

“Recompletion” means the completion for production of an existing wellbore in another formation from that which the well has been previously completed.

 

“Reserve” means that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

 

“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

“Resources” means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

 

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

 

“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 75 acre well-spacing) and is often established by regulatory agencies.

 

 

“Standardized measure” means the present value of estimated future after tax net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.

 

“Trend” means a geographic area with hydrocarbon potential.

 

“Undeveloped acreage” means lease 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.

 

“Unproved properties” means properties with no proved reserves.

 

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

 

“Wellbore” means the hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

 

“Working interest” means an interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

 

“Workover” means operations on a producing well to restore or increase production.

 

“WTI” means the West Texas Intermediate spot price.

 

 

 

 

 

 

 

 

 

 

PART I

 

 

Overview

 

Unless the context otherwise requires, all references in this report to the “Company,” “Yuma,” “our,” “us,” and “we” refer to Yuma Energy, Inc., a Delaware corporation, 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., a Delaware corporation, is an independent Houston-based exploration and production company focused on acquiring, developing and exploring for conventional and unconventional oil and natural gas resources. Historically, our operations have focused on onshore properties located in central and southern Louisiana and southeastern Texas where we have a long history of drilling, developing and producing both oil and natural gas assets. Finally, we have operated positions in Kern County, California, and non-operated positions in the East Texas Woodbine. Our common stock is listed on the NYSE American under the trading symbol “YUMA.”

 

Recent Developments

 

Senior Credit Agreement and Going Concern

 

The factors and uncertainties described below, as well as other factors which include, but are not limited to, declines in our production, our failure to establish commercial production on our Permian properties, and our substantial working capital deficit of approximately $37.0 million, raise substantial doubt about our ability to continue as a going concern. The Consolidated Financial Statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The Consolidated Financial Statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

 

On October 26, 2016, the Company and three of its subsidiaries, as the co-borrowers, entered into a credit agreement providing for a $75.0 million three-year senior secured revolving credit facility (the “Credit Agreement”) with Société Générale (“SocGen”), as administrative agent, SG Americas Securities, LLC, as lead arranger and bookrunner, and the lenders signatory thereto (collectively with SocGen, the “Lender”).

 

The borrowing base of the credit facility was $34.0 million as of December 31, 2018, and the Company was and is fully drawn under the credit facility leaving no availability on the line of credit. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of our assets.

 

The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and distributions or repurchase our capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable, and engage in certain transactions with affiliates.

 

In addition, the Credit Agreement requires us to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 on the last day of each quarter, a ratio of total debt to earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) ratio of not greater than 3.5 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and a ratio of EBITDAX to interest expense of not less than 2.75 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and cash and cash equivalent investments together with borrowing availability under the Credit Agreement of at least $4.0 million. The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral.

 

 

At December 31, 2018, we were not in compliance under the credit facility with our (i) total debt to EBITDAX covenant for the trailing four quarter period, (ii) current ratio covenant, (iii) EBITDAX to interest expense covenant for the trailing four quarter period, (iv) the liquidity covenant requiring us to maintain unrestricted cash and borrowing base availability of at least $4.0 million, and (v) obligation to make an interest only payment for the quarter ended December 31, 2018. In addition, we currently are not making payments of interest under the credit facility and anticipate future non-compliance under the credit facility going forward. Due to this non-compliance, as well as the credit facility maturity in 2019, we classified our entire bank debt as a current liability in our financial statements as of December 31, 2018. On October 9, 2018, we received a notice and reservation of rights from the administrative agent under the Credit Agreement advising that an event of default has occurred and continues to exist by reason of our noncompliance with the liquidity covenant requiring us to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the Lender may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the Lender has not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but may exercise one or more of these remedies in the future. We have commenced discussions with the Lender concerning a forbearance agreement or waiver of the event of default; however, there can be no assurance that the Lender and us will come to any agreement regarding a forbearance or waiver of the event of default. As required under the Credit Agreement, we previously entered into hedging arrangements with SocGen and BP Energy Company (“BP”) pursuant to International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”). On March 14, 2019, we received a notice of an event of default under our ISDA Agreement with SocGen (the “SocGen ISDA”). Due to the default under the ISDA Agreement, SocGen unwound all of our hedges with them. The notice provides for a payment of approximately $347,129 to settle our outstanding obligations thereunder related to SocGen’s hedges. On March 19, 2019, we received a notice of an event of default under our ISDA Agreement with BP (the “BP ISDA”). Due to the default under the ISDA Agreement, BP also unwound all of our hedges with them. The notice provides for a payment of approximately $775,725 to settle our outstanding obligations thereunder related to BP’s hedges.

 

Sale of Certain Non-Core Oil and Gas Properties

 

On August 20, 2018, we sold our 3.1% leasehold interest consisting of 9.8 net acres in one section in Eddy County, New Mexico for $127,400. On October 23, 2018, we sold substantially all of our Bakken assets in North Dakota for approximately $1.16 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $15,200. The Bakken assets represented approximately 12 barrels of oil equivalent per day of our production in the third quarter of 2018. On October 24, 2018, we sold certain deep rights in undeveloped acreage located in Grady County, Oklahoma for approximately $120,000. Proceeds of $1.0 million from these non-core asset sales were applied to the repayment of borrowings under the credit facility in October 2018.

 

Recent Entry into PSA on our California Properties

 

An Asset Purchase and Sale Agreement dated March 21, 2019, was executed on behalf of Pyramid Oil, LLC and Yuma Energy, Inc. (Sellers) and an undisclosed buyer (Buyer) covering the sale of all of Seller’s assets in Kern County, California. The purchase price for the sale is $2.1 million and the effective date is April 1, 2019. The parties expect to close the transaction by April 26, 2019. As additional consideration for the sale of the assets, if WTI Index for oil equals or exceeds $65 in six months following closing and maintains that average for twelve consecutive months then Buyer shall pay to the seller $250,000. Upon closing, we anticipate that the proceeds will be applied to the repayment of borrowings under the credit facility and/or working capital; however, there can be no assurance that the transaction will close.

 

Preferred Stock

 

As of December 31, 2018, we had 2,041,240 shares of our Series D preferred stock outstanding with an aggregate liquidation preference of approximately $22.6 million and a conversion price of $6.5838109 per share. The conversion price was adjusted from $11.0741176 per share to $6.5838109 per share as a result of our common stock offering that closed in October 2017. As a result, if all of our outstanding shares of Series D preferred stock were converted into common stock, we would need to issue approximately 3.4 million shares of common stock. The Series D preferred stock is paid dividends in the form of additional shares of Series D preferred stock at a rate of 7% per annum.

  

 

Operating Outlook

 

Recognizing the volatility in oil and natural gas prices, we plan to continue a disciplined approach in 2019 by emphasizing liquidity and value, enhancing operational efficiencies, and managing 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 to the extent that we can.

 

Business Strategy

Due to our lack of liquidity, as well as the continued volatile commodity price environment, we expect our capital spending plans to be limited in 2019 without the successful completion of a strategic alternative that improves the liquidity of the Company. In addition, we may slow down or forego the development of our properties to more closely manage our cash flows. We will be focused on lower risk and lower cost opportunities to maintain or minimize our declines in production and cash flow.

The key elements of our business strategy are:

 

 

 

Description of Major Properties

 

We are the operator of properties containing approximately 65.6% of our proved oil and natural gas reserves as of December 31, 2018. As operator, we are able to directly influence exploration, development and production operations.

 

As is common in the industry, we participate in non-operated properties and investments 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.

 

South Louisiana

 

We have operated and non-operated assets in many of the prolific oil and natural gas producing parishes of south Louisiana including Cameron, LaFourche, Livingston, St. Helena, St. Bernard, and Vermilion parishes. As of December 31, 2018, we had working interests in nine fields in south Louisiana, of which we operate six with an average operated working interest of 65.7%. The acreage associated with these leasehold positions is comprised of 18,536 gross acres and 3,172 net acres. The associated assets produce from a variety of conventional formations with oil, natural gas and natural gas liquids from depths of approximately 5,500 feet to almost 19,000 feet. The formations include the Lower Miocene, CibCarst, Dibert, Wilcox, Marg Tex, Het 1A, Tuscaloosa, Miocene Siphonina and Lower Planulina Cris R sands. The collective net production from this area averaged approximately 355 Bbl/d of oil, 5.5 MMcf/d of natural gas and 234 Bbl/d of natural gas liquids during the year ended December 31, 2018. The Chandeleur Sound Blk 71, State Lease 18194 #1 well located at our Main Pass 4 facility was shut in on February 27, 2019.  Prior to the well being shut in, it was producing approximately 20 net BOE/d. We are evaluating workover options to restore the well to production. Preliminary estimates to reestablish production for this well are estimated at a net cost of $300,000 to $400,000.

 

Our two largest fields in south Louisiana, based on estimated proved reserve value, are described below.

 

Lac Blanc Field, Vermilion Parish, Louisiana – We are the operator of the Lac Blanc Field where we have an average working interest of 81.3%. The field is comprised of 1,744 gross acres and 1,090 net acres where two wells, the SL 18090 #1 and #2, are producing from the Miocene Siphonina D-1 sand (18,700 feet sand). The net production from the field averaged approximately 64 Bbl/d of oil, 2.8 MMcf/d of natural gas and 156 Bbl/d of natural gas liquids during the year ended December 31, 2018.

 

 

The Lac Blanc LP#2 went off production on February 4, 2019.  Prior to going off-line, this well was producing approximately 995 net Mcf/d, or $150,000 per month in cash flow. We are reviewing options to put this well back online, but given our preliminary evaluation of the well, it is likely that costs could be significant, and due to our limited liquidity and the economics associated with the workover, there is no assurance we can fund the work. We will produce the well intermittently at a rate estimated to be less than 20% of the prior rate. The LP #1 and #2 are in the same reservoir so total reserves recovered from both wells are not expected to be materially impacted, but due to the disparate working interest (LP #1 and #2 of 62.5% and 100%, respectively) our net reserves would decrease should the LP #2 well not be put back into service.  In addition, our cash flows will be similarly impacted by this decreased production from the LP #2 well.

 

Bayou Hebert Field, Vermilion Parish, Louisiana – We have a 12.5% non-operated working interest in the Bayou Hebert Field, which is comprised of approximately 1,600 gross acres and 200 net acres with three wells completed in the Lower Planulina Cris R sands.  Two of the three wells are currently shut in. The net production from the field averaged approximately 39 Bbl/d of oil, 1.8 MMcf/d of natural gas and 76 Bbl/d of natural gas liquids during the year ended December 31, 2018. The one producing well in the Bayou Herbert Field is currently producing at a reduced rate of 375 Mcf/d net while the operator is repairing the SWD pumps. We expect the production to be restored to approximately 895 to 1,345 Mcf/d net in the second quarter of 2019.

 

Southeast Texas

 

We have operated and non-operated properties in southeast Texas containing both conventional and unconventional properties located in Jefferson and Madison counties. As of December 31, 2018, we had working interests in two fields, one of which we are the operator, with a working interest of 47.4%. The average working interest in the non-operated field was approximately 23.0%. The acreage associated with these leasehold positions consist of 24,444 gross acres and 591 net acres. The unconventional assets are developed primarily with horizontal wells in tight Woodbine sands producing oil, natural gas, and natural gas liquids from depths of approximately 8,000 feet to 9,000 feet. Typical development wells are drilled horizontally with lateral sections ranging from approximately 4,500 feet to 7,500 feet in length where multi-stage fracturing technology is employed. The collective net production from this area averaged approximately 26 Bbl/d of oil, 230 Mcf/d of natural gas and 40 Bbl/d of natural gas liquids during the year ended December 31, 2018.

 

California

 

We have assets in Kern County, California. As of December 31, 2018, we have a 100% working interest in five conventional fields with a leasehold position comprised of 1,192 gross acres inclusive of 263 fee or minerals only acres. These properties produce oil from a variety of conventional formations including the Pliocene, Miocene, Oligocene, and Eocene from depths ranging from approximately 800 feet to 6,300 feet. For the year ended December 31, 2018, net production from our California assets averaged approximately 78 Bbls/d of oil. On March 21, 2019, we entered into an Asset Purchase and Sale Agreement covering the sale of all of our assets in Kern County, California for $2.1 million, with an effective date of April 1, 2019. We expect to close the transaction by April 26, 2019.

 

Permian Basin

 

In 2017, we entered the Permian Basin through a joint venture with two privately held energy companies and established an AMI covering approximately 33,280 acres in Yoakum County, Texas, located in the Northwest Shelf of the Permian Basin. The primary target within the AMI is the San Andres formation. As of March 1, 2019, we held a 62.5% working interest in approximately 3,192 gross acres (1,995 net acres) within the AMI. We are the operator of the joint venture. In December 2017, we sold a 12.5% working interest in ten sections of the project on a promoted basis and sold an additional 12.5% working interest in the same ten sections under the same terms in January 2018. On November 8, 2017, we spudded a salt water disposal well, the Jameson SWD #1, and completed the well on December 8, 2017. The rig was then moved to our State 320 #1H horizontal San Andres well, which we spudded on December 13, 2017. The State 320 #1H well reached total depth on January 2, 2018, and was subsequently completed, fraced and placed on production on March 1, 2018. The well failed to establish commercial production and is currently shut in pending evaluation of the commerciality of the prospect area. Given the poor well performance and our limited liquidity, the ability to establish commercial production in the prospect area is uncertain at this time.

 

 

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 24 – 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 2018 other than to the SEC and the Department of Energy.

 

Estimated Proved Reserves

 

The table below summarizes our estimated proved reserves at December 31, 2018 based on reports prepared by NSAI. In preparing these reports, NSAI evaluated 100% of our properties at December 31, 2018. 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.

 

	Oil (MBbls)	Natural Gas Liquids (MBbls)	Natural Gas (MMcf)	Total (MBoe)(1)	Present Value Discounted at 10% ($ in thousands)(2)
Proved developed (3)
Lac Blanc Field (4)	301	586	10,704	2,671	$27,782
Bayou Hebert Field (4)	92	189	4,604	1,050	16,332
Other	1,138	36	1,568	1,433	21,942
Total proved developed	1,531	811	16,876	5,154	66,056
Proved undeveloped (3)
Lac Blanc Field(4)	-	-	-	-	-
Bayou Hebert Field (4)	-	-	-	-	-
Other	-	-	-	-	-
Total proved undeveloped	-	-	-	-	-
Total proved (3)	1,531	811	16,876	5,154	$66,056

 

 

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 24 – 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, 2018:

 

Present value of estimated future net revenues (PV10)	$66,056
Future income taxes discounted at 10%	-
Standardized measure of discounted future net cash flows	$66,056

 

 

 

Proved Undeveloped Reserves

 

At December 31, 2018, we had no proved undeveloped (“PUD”) reserves. The following table details the changes in PUD reserves for the year ended December 31, 2018 (in MBoe):

 

Beginning proved undeveloped reserves at January 1, 2018	1,295
Undeveloped reserves transferred to developed	-
Purchases of minerals-in-place	-
Sales of minerals-in-place	-
Extensions and discoveries	-
Production	-
Revisions	(1,295)
Proved undeveloped reserves at December 31, 2018	-

 

From January 1, 2018 to December 31, 2018, our PUD reserves decreased 1,295 MBoe, or 100%, from 1,295 MBoe to -0- MBoe, primarily due to our decision to write off our PUD reserves as a result of our liquidity and the uncertainty of our ability to fund their future development.

 

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 Estimates of Proved 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.

 

 

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 Vice President – Evaluations and Engineering was 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 12 years of industry experience, with 9 years or more of experience working as a reservoir engineer, senior reservoir engineering, team lead senior reservoir engineering and vice president of reservoir engineering. 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 Vice President – Evaluations and Engineering reports directly to our Interim Chief Executive Officer.

 

Internal Control over Preparation of Reserve Estimates

 

The design of our internal controls over our reserve estimation process was not effective as of December 31, 2018. 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 are reviewed quarterly and are updated at least 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 have been reviewed and compared to our internal estimates by our Vice President – Evaluations and Engineering 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.

 

 

Notwithstanding our foregoing controls and procedures, it came to management’s attention that the lease operating expense forecast for a significant field was misstated in our annual reserve report. Although we believe the error is isolated and not material to the reserve report itself, we recognize that the error causes a material amount of additional full cost ceiling impairment to be recorded. We re-assessed our internal controls over review of the third party reserve report and concluded that our controls were not effective because our review of the December 31, 2018 year-end reserve report lacked the precision necessary to identify an error in the field level lease operating expense forecast that could ultimately be material to the financial statements. See Item 9A of this report for further information.

 

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, 2018 and 2017, the average sales price per unit sold and the average production cost per unit are presented below.

 

	Years Ended December 31,
	2018	2017
Production volumes:
Crude oil and condensate (Bbls)	171,590	250,343
Natural gas (Mcf)	2,094,984	3,085,613
Natural gas liquids (Bbls)	100,234	131,155
Total (Boe) (1)	620,988	895,767
Average prices realized:
Crude oil and condensate (per Bbl)	$67.40	$50.32
Natural gas (per Mcf)	$3.19	$3.05
Natural gas liquids (per Bbl)	$32.19	$26.08
Production cost per Boe (2)	$13.67	$9.80

 

 

 

Our interests in Lac Blanc Field and Bayou Hebert Field represented 51.8% and 20.4%, respectively, of our total proved reserves as of December 31, 2018. Our interests in Lac Blanc Field and Bayou Hebert Field represented 40.0% and 20.1%, respectively, of our total proved reserves as of December 31, 2017. No other single field accounted for 15% or more of our proved reserves as of December 31, 2018 and 2017.

 

The net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 31, 2018 and 2017, the average sales price per unit sold and the average production cost per unit for our Lac Blanc Field are presented below.

 

	Years Ended December 31,
Lac Blanc Field	2018	2017
Production volumes:
Crude oil and condensate (Bbls)	23,295	25,070
Natural gas (Mcf)	1,031,579	1,101,824
Natural gas liquids (Bbls)	56,947	63,841
Total (Boe) (1)	252,172	272,548
Average prices realized:
Crude oil and condensate (per Bbl)	$67.95	$50.86
Natural gas (per Mcf)	$3.35	$3.22
Natural gas liquids (per Bbl)	$34.03	$27.76
Production cost per Boe (2)	$7.24	$6.63

 

 

 

The net quantities of oil, natural gas and natural gas liquids produced and sold by us for the years ended December 31, 2018 and 2017, the average sales price per unit sold and the average production cost per unit for our Bayou Hebert Field are presented below.

 

	Years Ended December 31,
Bayou Hebert Field	2018	2017
Production volumes:
Crude oil and condensate (Bbls)	14,382	25,479
Natural gas (Mcf)	656,300	1,236,615
Natural gas liquids (Bbls)	27,685	43,196
Total (Boe) (1)	151,450	274,778
Average prices realized:
Crude oil and condensate (per Bbl)	$70.11	$52.80
Natural gas (per Mcf)	$3.08	$3.10
Natural gas liquids (per Bbl)	$31.45	$27.85
Production cost per Boe (2)	$6.31	$4.51

 

 

Gross and Net Productive Wells

 

As of December 31, 2018, our total gross and net productive wells were as follows:

 

Oil (1)			Natural Gas (1)			Total (1)
Gross	Net		Gross	Net		Gross	Net
Wells	Wells		Wells	Wells		Wells	Wells
70	51		27	4		97	55

 

Gross and Net Developed and Undeveloped Acres

 

As of December 31, 2018, 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	18,536	3,172	-	-	18,536	3,172
Texas	25,304	619	4,626	1,995	29,930	2,614
Oklahoma	2,000	79	-	-	2,000	79
California	1,192	1,192	-	-	1,192	1,192
Total	47,032	5,062	4,626	1,995	51,658	7,057

 

 

As of December 31, 2018, we had leases representing 434 net acres (none of which were in the Lac Blanc or Bayou Herbert Fields) expiring in 2019; 1,246 net acres (none of which were in the Lac Blanc or Bayou Herbert Fields) expiring in 2020; and 315 net acres expiring in 2021.

 

Exploratory Wells and Development Wells

 

Set forth below for the years ended December 31, 2018 and 2017 is information concerning our drilling activity during the years indicated.

 

	Net Exploratory		Net Development		Total Net Productive
	Wells Drilled		Wells Drilled		and Dry Wells
Year	Productive	Dry	Productive	Dry	Drilled
2018	-	-	-	-	-
2017	-	0.5		-	0.5

 

Present Activities

 

At April 2, 2019, 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 WTI and adjusted to LLS or HLS. 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.

 

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 commodity derivative activities as discussed below in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commodity derivative Activities.”

 

Competition

 

The domestic oil and natural gas business is intensely competitive in the exploration for and acquisition of leasehold interests, reserves and in the producing and marketing of oil and natural gas production. Our competitors include national oil companies, major oil and natural gas companies, independent oil and natural gas companies, drilling partnership programs, individual producers, natural gas marketers, and major pipeline companies, as well as participants in other industries supplying energy and fuel to consumers. Many of our competitors are large, well-established companies. They likely are able to pay more for seismic information and lease rights on oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate oil and gas related transactions in a highly competitive environment.

 

Other Business Matters

 

Major Customers

 

During the years ended December 31, 2018 and 2017, sales to five customers accounted for approximately 80% and sales to five customers accounted for approximately 79%, respectively, of the Company’s total revenues.

 

 

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 oil and natural gas 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, development and production involve 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, acquire or produce 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 our 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.

 

As is common in the oil and natural gas industry, we do 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 and cash flows. For further discussion of these 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 opinion, are not so material as to detract substantially from the use or value of our oil and natural gas properties. Our oil and natural gas properties are typically subject, in one degree or another, one or more of the following:

 

 

 

 

 

 

 

 

 

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 quantity and value of our reserves. We believe that the burdens and obligations affecting our oil and natural gas properties are common in our industry with respect to the types of properties we own.

 

Operational Regulations

 

All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory and regulatory provisions affecting drilling, completion and production activities, 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 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, while some states allow the forced pooling or integration of land and leases to facilitate development, other states including Texas, where we operate, rely primarily or exclusively on voluntary pooling of land and leases. Accordingly, it may be difficult for us to form spacing units and therefore difficult to develop a project if we own or control 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, local authorities have imposed moratoria or other restrictions on exploration, development and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration, development and production to proceed.

 

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.

 

Regulation of Transportation of Natural Gas

 

The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

 

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

 

Regulation of Sales of Oil, Natural Gas and Natural Gas Liquids

 

The prices at which we sell oil, natural gas and natural gas liquids are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. FERC regulates the transportation of oil and liquids on interstate pipelines under the provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes. Intrastate transportation of oil, natural gas liquids and other products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. In addition, while sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

 

 

Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action that FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

 

Environmental Regulations

 

Our operations are also 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 (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 govern the permitting, construction and operation of a well or production related 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.

 

Beyond existing requirements, new programs and changes in existing programs may affect our business including 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 of 1980 (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct on certain categories 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 site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances found at the site. Under CERCLA, these potentially responsible persons may be subject to strict, 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 certain 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. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are not presently aware of any liabilities for which we may be held responsible that would materially or adversely affect us.

 

The Resource Conservation and Recovery Act of 1976 (“RCRA”), and comparable state statutes, regulate the generation, treatment, storage, transportation, disposal and clean-up of hazardous and solid (non-hazardous) wastes. With the approval of the EPA, the individual states can administer some or all of the provisions of RCRA, and some states have adopted their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil and natural gas are currently regulated under RCRA’s solid (non-hazardous) waste provisions. However, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. For example, in response to a lawsuit filed in the U.S. District Court for the District of Columbia by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. EPA action in response to the consent decree remains pending. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our, as well as the oil and natural gas E&P industry’s, costs to manage and dispose of generated wastes, which could have a material adverse effect on the industry as well as on our business.

 

 

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.

 

Water Discharges

 

The federal Clean Water Act and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In September 2015, the EPA and U.S. Army Corps of Engineers rule defining the scope of federal jurisdiction over Waters of the United States (the “WOTUS rule”) became effective; however, this rule has been stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit while the appellate court and numerous federal district courts consider lawsuits opposing implementation of the rule. The U.S. Supreme Court considered the issue of which court has jurisdiction to hear challenges to the WOTUS rule, and in January 2018 concluded that jurisdiction rests with the federal district courts. In addition, in 2017, President Trump issued an executive order directing the EPA and the U.S. Army Corps of Engineers to review the WOTUS rule and, if the agencies’ reviews find that the rule does not meet the executive order’s goal of promoting economic growth while reducing regulatory uncertainty, to initiate a new rulemaking to repeal or revise the rule. Pursuant to the executive order, in June 2017, the EPA and U.S. Army Corps of Engineers formally proposed to rescind the WOTUS rule. In January 2018, the EPA and the U.S. Army Corps of Engineers finalized a rule that would delay applicability of the WOTUS rule for two years, but a federal judge barred the agencies’ suspension of the rule in August 2018. Separately, a federal court in Georgia enjoined implementation of the rule in 11 states. However, in December 2018, the EPA and the U.S. Army Corps released a proposed rule that would replace the WOTUS rule and significantly reduce the waters subject to federal regulation under the CWA. Such proposal is currently subject to public review and comment, after which additional legal challenges are anticipated. The scope of the jurisdictional reach of the Clean Water Act will likely remain uncertain for several years.

 

The process for obtaining permits has the potential to delay our operations. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. The Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990 (“OPA”), impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.

 

Our oil and natural gas production also generates salt water, which we dispose of by underground injection. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program, 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. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. 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 response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells. In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations.

 

 

Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations. 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. In particular, the well completion technique known as hydraulic fracturing is used to stimulate production of oil and natural gas has come under increased scrutiny by the environmental community, and many local, state and federal regulators. 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 depths to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with substantially all of the wells for which we are the operator.

 

The SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process.

 

Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the fracturing process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells.

 

In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

 

In addition, on March 26, 2015, the Bureau of Land Management (the “BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands. Also, on November 15, 2016, the BLM finalized a waste preventing rule to reduce the flaring, venting and leaking of methane from oil and natural gas operations on federal and Indian lands. On March 28, 2017, President Trump signed an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule; however, a coalition of environmentalists, tribal advocates and the state of California filed lawsuits challenging the rule rescission. Also, on February 22, 2018, the BLM published proposed amendments to the waste prevention rule that would eliminate certain air quality provisions and, on April 4, 2018, a federal district court stayed certain provisions of the 2016 rule. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations.

 

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

 

 

Some states and local jurisdictions in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. If new or more stringent state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

 

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

 

Air Emissions

 

The federal Clean Air Act and comparable state laws restrict 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 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.

 

In 2012 and 2016, the EPA issued New Source Performance Standards to regulate emissions of sources of volatile organic compounds (“VOCs”), sulfur dioxide, air toxics and methane from various oil and natural gas exploration, production, processing and transportation facilities. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rule making to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. In June 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. On September 11, 2018, the EPA proposed targeted improvements to the rule, including amendments to the rule’s fugitive emissions monitoring requirements, and expects to “significantly reduce” the regulatory burden of the rule in doing so. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

 

In October 2015, the EPA announced that it was lowering the primary national ambient air quality standards (“NAAQS”) for ozone from 75 parts per billion to 70 parts per billion. In July 2018, the EPA finished issuing area designations with respect to ground-level ozone for U.S. counties as either “attainment/unclassifiable” or “unclassifiable.” Reclassification of areas of state implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

 

 

Climate Change

 

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) endanger public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards for these emissions. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operations. Also, as noted above, the EPA has promulgated a New Source Performance Standard related to methane emissions from the oil and natural gas source category.

 

While Congress has considered legislation related to the reduction of GHG emissions in the past, no significant legislation to reduce GHG emissions has been adopted at the federal level. In the absence of Congressional action, a number of state and regional GHG restrictions have emerged. At the international level, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November 2016. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges from participating nations to voluntarily limit or reduce future emissions. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.

 

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. Currently, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Finally, it should also be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events; if any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

 

National Environmental Policy Act

 

Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act (“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. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.

 

 

Threatened and endangered species, migratory birds and natural resources

 

Various federal and state 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 (“ESA”), the Migratory Bird Treaty Act and the Clean Water Act. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. As a result of a 2011 settlement agreement, the FWS was required to make a determination on listing of more than 250 species as endangered or threatened under the FSA by no later than completion of the agency’s 2017 fiscal year. The FWS missed the deadline but reportedly continues to review new species for protected status under the ESA pursuant to the settlement agreement. 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 may result. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds we believe that we are in substantial compliance with the ESA and the Migratory Bird Treaty Act, and we are not aware of any proposed ESA listings that will materially affect our operations. The federal government in the past has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce our oil and natural gas reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

 

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, including, but not limited to, the federal Emergency Planning & Community Right-to-Know Act, govern record keeping and reporting of the use and release of hazardous substances and may require that information be provided to state and local government authorities, as well as the public.

 

Occupational Safety and Health Act

 

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

 

State Regulation

 

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure our stockholders that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

 

 

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

 

Related Insurance

 

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration, development and production activities. However, this insurance is limited to activities at the well site, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

 

Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue.

 

Employees and Principal Office

 

As of December 31, 2018, we had 22 full-time employees and one part-time employee. 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.

 

Executive Officers of the Company

 

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

 

		Executive
Name		Officer Since		Age		Position
Anthony C. Schnur		March 2019		53		Interim Chief Executive Officer and Chief Restructuring Officer
James J. Jacobs		October 2016		40		Chief Financial Officer, Treasurer and Corporate Secretary

 

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

 

Anthony C. Schnur has been our Interim Chief Executive Officer since March 28, 2019, following the termination of our Chief Executive Officer on March 27, 2019, and our Chief Restructuring Officer since March 1, 2019, following the resignation of our President and Chief Operating Officer on January 24, 2019. Previously, Mr. Schnur served as Managing Director of Capodian, LLC since September 2017. From December 2012 through June 2017, Mr. Schnur was a director and Chief Executive Officer of Camber Energy, Inc. (formerly Lucas Energy, Inc.) (“Camber”). Mr. Schnur also served as Chief Financial Officer of Camber from November 2012 to April 2013 and interim Chief Financial Officer from September 2013 to August 2016. From January 2010 through October 2012, Mr. Schnur served as Chief Financial Officer of Chroma Oil & Gas, LP, a private equity backed E&P with operations in Texas and Louisiana. From August 2015 through December 2016, Mr. Schnur served on the Board of Directors of Tombstone Exploration Corporation, an exploration and development company, located within the historic Tombstone Mining District, Cochise County, Arizona. Mr. Schnur obtained a Bachelor of Science in Business Administration in Finance from Gannon University in 1987 and a Masters of Business Administration from Case Western Reserve University in 1992. Mr. Schnur is a member of the Independent Petroleum Association of America; Texas Independent Producers & Royalty Owners Association; and the ADAM-Houston, Acquisitions and Divestitures Group.

 

 

James J. Jacobs has been our Chief Financial Officer, Treasurer and Corporate Secretary since the closing of the Davis Merger on October 26, 2016. He was the Chief Financial Officer, Treasurer and Corporate Secretary of Yuma California from December 2015 through October 26, 2016. He served as Vice President – Corporate and Business Development of Yuma California immediately prior to his appointment as Chief Financial Officer in December 2015 and has been with us since 2013. He has 16 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.

 

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, 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. The SEC 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.

 

 

 

 

 

 

 

We are subject to various 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. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in this report under “Cautionary Statement Regarding Forward-Looking Statements” and other information included and incorporated by reference into this Annual Report on Form 10-K.

 

Inadequate liquidity could materially and adversely affect our business operations.

 

We have significant outstanding indebtedness under our credit facility. As of December 31, 2018, we had fully drawn the $34.0 million available under our credit facility and were in default under the credit agreement. In addition, we have experienced significant declines in our production and have limited cash flow to fund the ongoing operations of our business. Due to this limited liquidity and decreased cash flow, we may not be able to maintain production, which could lead to continued deterioration in our financial condition.

 

Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend upon our ability to consummate asset sales and/or a merger transaction at values consistent with our reported reserve values, which is beyond our control.  If a transaction closes, our future operating performance and financial condition will be affected by prevailing economic conditions and financial, business and other factors, many of which we also cannot control. In any event, we cannot assure you that our business will generate sufficient cash flows from operations, or that future capital will be available to us under a new credit facility or otherwise, in an amount sufficient to fund our liquidity needs. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems, and we might be required to seek additional debt or equity financing or to dispose of material assets or operations to meet our debt service and other obligations, or we may fail to continue as a going concern.  We cannot assure you that we would be able to raise capital through debt or equity financings on terms acceptable to us or at all, or that we could consummate dispositions of assets or operations for fair market value, in a timely manner or at all.  Furthermore, any proceeds that we could realize from any financings or dispositions may not be adequate to meet our debt service or other obligations then due.

 

Our auditors and management have expressed substantial doubt about our ability to continue as a going concern.

 

As disclosed in the financial statements, we incurred net losses attributable to common shareholders of $17.1 million and $6.8 million for the years ended December 31, 2018 and 2017, respectively. At December 31, 2018, our total current liabilities of $44.2 million exceed our total current assets of $7.2 million. Additionally, we are in violation of our debt covenants, have stopped paying interest under our credit facility, have experienced recent production declines, have extremely limited liquidity, and have suffered recurring losses from operations. We believe these circumstances raise substantial doubt about our ability to continue as a going concern.

 

Our ability to continue as a going concern is dependent on the sale of substantially all of our assets and/or a merger transaction. If we are not able to generate the funds needed to cover our ongoing expenses, then we may be forced to cease operations or seek bankruptcy protection, in which event our stockholders could lose their entire investment.

 

We are in breach of multiple covenants under our credit agreement and we are relying on our lenders’ forbearance from exercising their rights under the credit agreement, which include the right to foreclose upon our assets.

 

We remain in breach of multiple covenants under our credit agreement with our lenders. There is no assurance that the lenders will not declare a default and seek immediate repayment of the entire debt borrowed under the credit facility because of these breaches.

 

 

We are subject to compliance under the NYSE American LLC continued listing standards as set forth in Section 1003(f)(v) of the NYSE American Company Guide, related to securities selling price.

 

On January 4, 2019, we received a letter from NYSE American stating that our common stock has been selling for a low price per share for a substantial period of time and, pursuant to Section 1003(f)(v) of the Company Guide, our continued listing is predicated on it effecting a reverse stock split of our common stock or otherwise demonstrating sustained price improvement within a reasonable period of time, which NYSE American had determined to be no later than July 4, 2019, and subject to our compliance with other continued listing requirements and the trading price remaining above a required $0.06 minimum per share.

 

If we are not able to access additional capital in significant amounts, we may not be able to continue to develop our current prospects and properties, or we may forfeit our interest in certain prospects and we may not be able to continue to operate our business.

 

We need significant capital to continue to operate our properties and continue operations. In the near term, we intend to finance our capital expenditures with cash flow from operations, and possibly the future issuance of debt and/or equity securities. Our cash flow from operations and access to capital is subject to a number of variables, including, among others:

 

 

 

 

 

 

 

 

Our operations and other capital resources may not provide cash in sufficient amounts to maintain future levels of capital expenditures. Further, our actual capital expenditures in 2019 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include refinancing existing debt, joint venture partnerships, production payment financings, sales of non-core property assets, or offerings of debt or equity securities. We may not be able to obtain any form of financing on terms favorable, or at all.

 

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings. The occurrence of such events may prevent us from continuing to operate our business and our common stock and preferred stock may not have any value.

 

 

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

 

Currently, our principal sources of liquidity are cash on hand, cash from operating activities, proceeds from the sale of assets, and potential proceeds from capital market transactions, including the sale of debt and equity securities. For the year ended December 31, 2018, we had outstanding borrowing of $34.0 million under our credit facility and our total borrowing base was $34.0 million. Since significant amounts of capital are required for companies to participate in the business of exploration for and development of oil and natural gas resources, we are dependent on improving our cash flow and revenue, as well as receipt of additional working capital, to fund continued development and implementation of our business plan. Adverse developments in our business or general economic conditions may require us to raise additional financing at prices or on terms that are disadvantageous to existing stockholders. We may not be able to obtain additional capital at all and may be forced to curtail or cease our operations. We will continue to rely on equity or debt financing and the sale of working interests to finance operations until such time, if ever, that we generate sustained positive cash flow. The inability to obtain necessary financing will likely adversely impact our ability to develop our properties and to expand our business operations.

 

Our credit facility has substantial restrictions and financial covenants and our ability to regain compliance with those restrictions and covenants is highly unlikely. 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, which we were not in compliance with as of December 31, 2018. Our ability to comply with these restrictions and covenants in the future is highly doubtful 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, as well as our inability to make interest payments, has resulted in a default under those agreements, which has caused all of our existing indebtedness to be immediately due and payable. Reductions in our borrowing base under our credit facility could also arise from several factors, including but not limited to:

 

 

 

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 set our current borrowing base at $34.0 million. Prices of crude oil below $50.00 per Bbl 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 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. Any 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.

 

We are currently unable to comply with the restrictions and covenants in the agreements governing our indebtedness, resulting in 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.

 

We are in default under the agreements governing our indebtedness 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. Since we are in 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. We cannot assure you that we will be granted waivers or amendments to our defaults under the debt 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 remains the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease.

 

Oil, natural gas and natural gas liquids prices are volatile. Their prices at times since 2014 have adversely affected, and in the future may adversely affect, our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments. Volatile and lower prices may also negatively impact our stock price.

 

The prices we receive for our oil, natural gas and natural gas liquids production heavily influence our revenues, profitability, access to capital and future rate of growth. These hydrocarbons are commodities, and therefore, their prices may be subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil, natural gas and natural gas liquids has been volatile. For example, during the period from January 1, 2014 through December 31, 2018, the West Texas Intermediate (“WTI”) spot price for oil declined from a high of $107.95 per Bbl in June 2014 to $26.19 per Bbl in February 2016. The Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu in February 2014 to a low of $1.49 per MMBtu in March 2016. During 2018, WTI spot prices ranged from $44.48 to $77.41 per Bbl and the Henry Hub spot price of natural gas ranged from $2.49 to $6.24 per MMBtu. Likewise, natural gas liquids, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have experienced significant declines in realized prices since the fall of 2014. The prices we receive for oil, natural gas and natural gas liquids we produce and our production levels depend on numerous factors beyond our control, including:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lower oil, natural gas and natural gas liquids prices have and may continue to reduce our cash flows and borrowing capacity. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our hydrocarbon reserves as existing reserves are depleted. A decrease in prices could render development projects and producing properties uneconomic, potentially resulting in a loss of mineral leases. Low commodity prices have, at times, caused significant downward adjustments to our estimated proved reserves, and may cause us to make further downward adjustments in the future. Furthermore, our borrowing capacity could be significantly affected by decreased prices. A sustained decline in oil, natural gas and natural gas liquids prices could adversely impact our borrowing base in future borrowing base redeterminations, which could trigger repayment obligations under the Credit Agreement to the extent our outstanding borrowings exceed the redetermined borrowing base and could otherwise materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. In addition, lower oil, natural gas and natural gas liquids gas prices may cause a decline in the market price of our shares. As of the date of this report, we do not have any commodity derivative contracts that hedge our oil, natural gas or natural gas liquids price risk.

 

As a result of low prices for oil, natural gas and natural gas liquids, we have taken and may be required to take significant future write-downs of the financial carrying values of our properties.

 

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and 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 have been required to, and may be required to significantly write-down the financial carrying value of our oil and natural gas properties, which constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are recorded.

 

 

A write-down could occur when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated proved oil and natural gas reserves, if operating costs or development costs increase over prior estimates, or if our drilling and workover program is unsuccessful.

 

The capitalized costs of our oil and natural gas properties subject to amortization, net of accumulated 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 unproved properties not subject to amortization. If the capitalized cost of these proved properties subject to amortization exceeds these estimated future net cash flows, we would be required to record impairment charges to reduce the capitalized costs of our oil and natural gas properties. These types of charges will reduce our earnings and stockholders’ equity and could adversely affect our stock price. Unproved properties not subject to amortization are evaluated quarterly, and this review may result in these properties being moved into our oil and gas properties subject to amortization.

 

We periodically assess our properties for impairment based on future estimates of proved and non-proved reserves, oil and natural gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Once incurred, an impairment charge cannot be reversed at a later date even if price increases of oil and/or natural gas occur and in the event of increases in the quantity of our estimated proved reserves.

 

If oil, natural gas and natural gas liquids prices fall below current levels for an extended period of time and all other factors remain equal, we may incur impairment charges in the future. Such charges could have a material adverse effect on our results of operations for the periods in which they are recorded. See Note 6. Asset Impairments and Note 7. Property, Plant, and Equipment, Net in the Notes to the Consolidated Financial Statements included in this report for additional information.

 

We have historically incurred losses and may not achieve profitability in the future.

 

We have incurred losses from operations during our history in the oil and natural gas business. We had an accumulated deficit of approximately $36.3 million as of December 31, 2018. Our ability to be profitable in the future will depend on successfully addressing our going-concern issues, near-term capital needs and implementing economic acquisition, development and production activities, all of which are subject to many risks beyond our control.

 

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 oil, natural gas or natural gas liquids 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 natural gas liquids, 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 would likely adversely affect our cash flow.

 

 

Our oil, natural gas and natural gas liquids are sold in a limited number of geographic markets so an oversupply in any of those areas could have a material negative effect on the price we receive.

 

Our oil, natural gas and natural gas liquids are sold in a limited number of geographic markets and each has a fixed amount of storage and processing capacity. As a result, if such markets become oversupplied with oil, natural gas and/or natural gas liquids, it could have a material negative effect on the prices we receive for our products and therefore an adverse effect on our financial condition and results of operations. There is a risk that refining capacity in the U.S. Gulf Coast may be insufficient to refine all of the light sweet crude oil being produced in the United States. If light sweet crude oil production remains at current levels or continues to increase, demand for our light crude oil production could result in widening price discounts to the world crude prices and potential shut in or reduction of production due to a lack of sufficient markets despite the lift on prior restrictions on the exporting of oil and natural gas from the United States.

 

We may not be able to drill wells on a substantial portion of our leasehold 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. Deterioration in commodities prices may also make drilling certain properties or acreage uneconomic. Our actual drilling activities and future drilling budget will depend on prior 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 business, financial condition and results of operations.

 

Approximately 28.3% of our net leasehold acreage is undeveloped and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

 

As of December 31, 2018, approximately 28.3% of our net leasehold acreage was undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income, are highly dependent on successfully developing our undeveloped leasehold acreage. We may also lose the right to claim certain proved undeveloped reserves in our engineering and financial reports if we cannot demonstrate the probability of developing those reserves within prescribed time frames, usually within five years. Further, to the extent we determine that it is not economic to develop particular undeveloped acreage; we may intentionally allow leases to expire.

 

Unless we replace our reserves with new reserves and develop those reserves, our production and estimated reserves will decline, which may adversely affect our financial condition, results of operations and/or future cash flows.

 

Producing oil and natural gas reservoirs are generally characterized by declining production rates that may vary depending upon reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well, particularly horizontal wells. Estimates of the decline rate of an oil or natural gas well are inherently imprecise and may be 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. Unless we conduct successful ongoing acquisition and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Thus, our estimated future oil and natural gas reserves and production and, therefore, our cash flows and results of operations are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, our cash flows and the value of our reserves will decrease, adversely affecting our business, financial condition and results of operations.

 

 

Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions will materially affect the quantities and the value of those reserves.

 

This report contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by SEC regulations 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 and requires significant decisions, complex analyses and assumptions in evaluating available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

 

Our 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 will likely materially affect the estimated quantities and the estimated value of our reserves. In addition, we may later adjust estimates of proved reserves to reflect production history, results of exploration and development activities, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

 

Quantities of estimated proved reserves are based on economic conditions in existence during the period of assessment. Changes to oil, natural gas and natural gas liquids prices in the markets for these commodities may shorten the economic lives of certain fields because it may become uneconomical to produce all recoverable reserves in such fields, which may reduce proved reserves estimates.

 

Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decrease earnings or result in losses through higher depletion expense. These revisions, as well as revisions in the assumptions of future estimated cash flows of those reserves, may also trigger impairment losses on certain properties, which may result in non-cash charges to earnings. See Note 7 – Property, Plant, and Equipment, Net in the Notes to the Consolidated Financial Statements included in this report.

 

At December 31, 2018, none 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, natural gas and natural gas liquids 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 estimated proved reserves may 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 estimated proved reserves set forth in this report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2018 and 2017, 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 arithmetic 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:

 

 

 

 

 

The timing of both our production and incurring expenses related to developing and producing 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 our business or the oil and natural gas industry in general. As a corporation, we are treated as a taxable entity for statutory 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 estimates included in this report which could have a material effect on the value of our estimated reserves.

 

 

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:

 

 

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.

 

The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oilfield 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.

 

 

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

 

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

 

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:

 

 

We participate in oil and natural gas leases with third parties who may not be able to fulfill their commitments to our projects.

 

In some cases, we operate but 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 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 success and timing of our drilling, development and production activities on such properties operated by third-parties therefore depends upon a number of factors, including:

 

 

 

 

 

 

 

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. As a result, our ability to exercise influence over the operations of some of our current or future properties is and may be limited.

 

Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

 

We design and generate in-house 3-D seismic survey programs on many of our projects. We may use seismic studies to assist with assessing prospective drilling opportunities on current properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

 

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.

 

In assessing potential acquisitions, we consider information available in the public domain and information provided by the seller. In the event publicly available data is limited, then, by necessity, we may rely to a large extent on information that may only be available from the seller, particularly with respect to drilling and completion costs and practices, geological, geophysical and petrophysical data, detailed production data on existing wells, and other technical and cost data not available in the public domain. Accordingly, the review and evaluation of businesses or properties to be acquired may not uncover all existing or relevant data, obligations or actual or contingent liabilities that could adversely impact any business or property to be acquired and, hence, could adversely affect us as a result of the acquisition. These issues may be material and could include, among other things, unexpected environmental liabilities, title defects, unpaid royalties, taxes or other liabilities. If we acquire properties on an “as-is” basis, we may have limited or no remedies against the seller with respect to these types of problems.

 

The success of any acquisition that we complete will depend on a variety of factors, including our ability to accurately assess the reserves associated with the acquired properties, assumptions related to future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are often inexact and subjective. As a result, we may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales or operations.

 

Our ability to achieve the benefits that we expect from an acquisition will also depend on our ability to efficiently integrate the acquired operations. Management may be required to dedicate significant time and effort to the integration process, which could divert its attention from other business opportunities and concerns. The challenges involved in the integration process may include retaining key employees and maintaining employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding acquired properties.

 

 

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:

 

 

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. 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 results of operations and financial condition.

 

 

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

 

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Federal, state and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we currently conduct operations, or in the future plan to conduct operations. Consequently, we could be subject to additional levels of regulation, operational delays or increased operating costs and could have additional regulatory burdens imposed upon us that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

 

From time to time, for example, legislation has been proposed in Congress to amend the SDWA to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. Further, the EPA completed a study finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing. For example, on March 26, 2015, the BLM published a final rule governing hydraulic fracturing on federal and Indian lands. Also, on November 15, 2016, the BLM finalized a waste preventing rule to reduce the flaring, venting and leaking of methane from oil and natural gas operations on federal and Indian lands. On March 28, 2017, President Trump signed an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule; however, a coalition of environmentalists, tribal advocates and the state of California filed lawsuits challenging the rule rescission. Also, on February 22, 2018, the BLM published proposed amendments to the waste prevention rule that would eliminate certain air quality provisions and, on April 4, 2018, a federal district court stayed certain provisions of the 2016 rule. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations. Further, legislation to amend the SDWA to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several states and local jurisdictions in which we operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

 

More recently, federal and state governments have begun investigating whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. For example, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals for fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters, and disposal or storage of fracturing wastewater in unlined pits. The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

 

The proliferation of regulations may limit our ability to operate. 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. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

 

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids we produce.

 

In response to findings that emissions of carbon dioxide, methane and other GHGs present a danger to public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish PSD, construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards for these emissions.

 

EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operations.

 

Furthermore, in June 2016, the EPA finalized rules, known as Subpart OOOOa, that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. Following the change in presidential administration, there have been attempts to modify these regulations, and litigation concerning the regulations is ongoing. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal methane regulation of the oil and gas industry remains a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities.

 

While Congress has from time to time considered legislation to reduce emissions of GHGs, no significant legislation to reduce GHG emissions has been adopted at the federal level. In the absence of Congressional action, a number of state and regional GHG restrictions have emerged. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulation programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and gas we produce could also have the effect of lowering the value of our reserves.

 

Demand for our products may also be adversely affected by conservation plans and efforts undertaken in response to global climate change, including plans developed in connection with the recent Paris climate conference agreement reached in December 2015, which entered into force in November 2016. However, in August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Climate Agreement. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. It should also be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their GHG emissions. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to causation or contribution to the asserted damage, or to other mitigating factors.

 

 

Our operations are substantially dependent on the availability, use and disposal of water. New legislation and regulatory initiatives or restrictions relating to water disposal wells could have a material adverse effect on our future business, financial condition, operating results and prospects.

Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas and natural gas liquids, which could have an adverse effect on our business, financial condition and results of operations. Wastewaters from our operations typically are disposed of via underground injection. Some studies have linked earthquakes in certain areas to underground injection, which is leading to greater public scrutiny of disposal wells. Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas, or that limit the withdrawal, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

 

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.

 

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and natural gas exploration, development and production companies. Such legislative changes have included, but not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. The Tax Cuts and Jobs Act of 2017 (the “TCJA”) did not directly affect deductions currently available to the oil and natural gas industry but any future changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

 

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.

 

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:

 

 

 

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.

 

Red Mountain Capital Partners LLC and its affiliates (“Red Mountain”) hold 23% of the voting power of our outstanding shares which gives Red Mountain a significant interest in the Company.

 

Red Mountain holds approximately 23% of our outstanding shares of common stock on an as-converted basis. Accordingly, Red Mountain has the ability to exert a significant degree of influence over our management and affairs and, as a practical matter, will significantly influence corporate actions requiring stockholder approval, irrespective of how our other stockholders may vote, including the election of directors, amendments to our certificate of incorporation and bylaws, and the approval of mergers and other significant corporate transactions, including a sale of substantially all of our assets, and Red Mountain may vote its shares in a manner that is adverse to the interests of our minority stockholders. For example, Red Mountain may be able to prevent a merger or similar transaction, including a transaction in which stockholders will receive a premium for their shares, even if our other stockholders are in favor of such transaction. Further, Red Mountain’s position might adversely affect the market price of our common stock to the extent investors perceive disadvantages in owning shares of a company with a significant stockholder.

 

A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

 

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, as well as conduct reservoir modeling and reserve estimation for compliance reporting.

 

We are dependent on digital technologies including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees, business partners, and stockholders, analyze seismic and drilling information, estimate quantities of oil and natural gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production and financial institutions are also dependent on digital technology. The technologies needed to conduct oil and natural gas exploration, development and production activities make certain information the target of theft or misappropriation.

 

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for the purposes of misappropriating assets or sensitive information, corrupting data, causing operational disruption, or result in denial-of-service on websites.

 

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.

 

We may not be able to keep pace with technological developments in the industry.

 

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we are in a position to do so. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies used now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, the business, financial condition, and results of operations could be materially adversely affected.

 

 

Terrorist attacks aimed at energy operations could adversely affect our business.

 

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, the infrastructure depended upon for transportation of products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

 

We depend on our key personnel, the loss of which could adversely affect our operations and financial performance.

 

We depend, to a large extent, on the services of a limited number of senior management personnel and directors. The loss of the services of our Interim Chief Executive Officer and Chief Restructuring Officer could negatively impact our future operations. We believe that our success is also dependent on our ability to continue to retain the services of a limited number of skilled technical personnel. Our inability to retain a new chief executive officer or retain other skilled technical personnel could have a material adverse effect on our financial condition, future cash flows and the results of operations.

 

Risks Related to the Ownership of our Common Stock

 

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 oil and natural gas industry, general economic conditions or other events or factors that are beyond our control.

 

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 American 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 was 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 American, 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 Amended and Restated Certificate of Incorporation authorizes 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 stockholders. 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.

 

Our failure to fulfill all of our registration requirements may cause us to suffer liquidated damages, which may be very costly.

 

Pursuant to the terms of the Registration Rights Agreement that we entered into with certain of our stockholders, we filed a registration statement with respect to securities issued and are required to maintain the effectiveness of such registration statement. There can be no assurance that we will be able to maintain the effectiveness of any registration statement, and therefore there can be no assurance that we will not incur damages with respect to such agreement.

 

Because we have no plans to pay dividends on our common stock, stockholders must look solely to a possible 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, stockholders must look solely to appreciation of our common stock to realize a gain on their investment, which may not occur.

 

Our Series D preferred stock has rights, preferences and privileges that are not held by, and are preferential to, the rights of our common stockholders. Such preferential rights could adversely affect our liquidity and financial condition and may result in the interests of the holders of the Series D preferred stock differing from those of our common stockholders.

 

In the event of any liquidation, dissolution or winding up of our company, whether voluntary or involuntary, or any other transaction deemed a liquidation event pursuant to the Certificate of Designation, including a sale of our company (a “Liquidation”), each holder of outstanding shares of our Series D preferred stock will be entitled to be paid out of our assets available for distribution to stockholders, before any payment may be made to the holders of our common stock, an amount per share equal to the original issue price, plus accrued and unpaid dividends thereon. If, upon such Liquidation, the amount that the holders of Series D preferred stock would have received if all outstanding shares of Series D preferred stock had been converted into shares of our common stock immediately prior to such Liquidation would exceed the amount they would receive pursuant to the preceding sentence, the holders of Series D preferred stock will receive such greater amount.

 

Dividends on the Series D preferred stock are cumulative and accrue quarterly, whether or not declared by our board of directors, at the rate of 7.0% per annum on the sum of the original issue price plus all unpaid accrued and unpaid dividends thereon, and payable in additional shares of Series D preferred stock. In addition to the dividends accruing on shares of Series D preferred stock described above, if we declare certain dividends on our common stock, we will be required to declare and pay a dividend on the outstanding shares of our Series D preferred stock on a pro rata basis with the common stock, determined on an as-converted basis. Our obligations to the holders of Series D preferred stock could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

 

 

There may be significant future dilution of our common stock.

 

We have a significant amount of derivative securities outstanding, which upon conversion, would result in substantial dilution. For example, the conversion of outstanding shares of Series D preferred stock in full could result in the issuance of approximately 3.5 million shares of common stock. To the extent outstanding stock appreciation rights under our long-term incentive plan are exercised or additional shares of restricted stock are issued to our employees, holders of our common stock will experience dilution. Furthermore, if we sell additional equity or convertible debt securities, such sales could result in further dilution to our existing stockholders and cause the price of our outstanding securities to decline.

 

If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about our business, our stock price and trading volume could decline.

 

The trading market for our common stock will depend in part upon the research and reports that securities or industry analysts publish about us and our business. We do not currently have and may never obtain research coverage by securities and industry analysts. If no analysts commence coverage of our company, the trading price of our common stock might be negatively impacted. If we obtain securities or industry analyst coverage and if one or more of the analysts who covers us downgrades our stock or publishes inaccurate or unfavorable research about our business, our stock price would likely decline. If one or more of these analysts ceases coverage or fails to report about us on a regular basis, demand for our stock could decrease, which could cause our stock price and trading volume to decline.

 

 

None.

 

 

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.

 

 

 

Yuma Energy, Inc. v. Cardno PPI Technology Services, LLC Arbitration

 

On May 20, 2015, counsel for Cardno PPI Technology Services, LLC (“Cardno PPI”) sent a notice of the filing of liens totaling $304,209 on our Crosby 14 No. 1 Well and Crosby 14 SWD No. 1 Well in Vernon Parish, Louisiana. We disputed the validity of the liens and of the underlying invoices, and notified Cardno PPI that applicable credits had not been applied. We invoked mediation on August 11, 2015 on the issues of the validity of the liens, the amount due pursuant to terms of the parties’ Master Service Agreement (“MSA”), and PPI Cardno’s breaches of the MSA. Mediation was held on April 12, 2016; no settlement was reached.

 

On May 12, 2016, Cardno filed a lawsuit in Louisiana state court to enforce the liens; the Court entered an Order Staying Proceeding on June 13, 2016, ordering that the lawsuit “be stayed pending mediation/arbitration between the parties.” On June 17, 2016, we served a Notice of Arbitration on Cardno PPI, stating claims for breach of the MSA billing and warranty provisions. On July 15, 2016, Cardno PPI served a Counterclaim for $304,209 plus attorneys’ fees. The parties selected an arbitrator, and the arbitration hearing was held on March 29, April 12 and April 13, 2018. The parties submitted closing statements on April 30, 2018, and are awaiting a ruling by the arbitrator. Management intends to pursue our claims and to defend the counterclaim vigorously. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on our consolidated financial statements.

 

 

The Parish of St. Bernard v. Atlantic Richfield Co., et al

 

On October 13, 2016, two of our subsidiaries, Yuma Exploration and Production Company, Inc. (“Exploration”) and Yuma Petroleum Company (“YPC”), were named as defendants, among several other defendants, in an action by the Parish of St. Bernard in the Thirty-Fourth Judicial District of Louisiana. The petition alleges violations of the State and Local Coastal Resources Management Act of 1978, as amended, in the St. Bernard Parish.  We notified our insurance carrier of the lawsuit.  Management intends to defend the plaintiffs’ claims vigorously.  The case was removed to federal district court for the Eastern District of Louisiana. A motion to remand was filed and the Court officially remanded the case on July 6, 2017. Exceptions for Exploration, YPC and the other defendants were filed; however, the hearing for such exceptions was continued from the original date of October 6, 2017 to November 22, 2017. The November 22, 2017 hearing was continued without date because the parties agreed the case will be de-cumulated into subcases, but the details of this are yet to be determined. The case was removed again on other grounds on May 23, 2018. On May 25, 2018, a Motion was filed on behalf of certain defendants with the United States Judicial Panel for Multi District Litigation (“JPMDL”) for consolidated proceedings for all 41 pending cases filed in Louisiana with claims that are substantially the same as those in this case. A 42nd case has been added as a “tag-along”. In the interim, plaintiffs timely filed their Motion to Remand in the case. Hearing on the Motion before the JPMDL was held on July 26, 2018 in Santa Fe, New Mexico, and the JPMDL denied centralization by Order dated July 31, 2018. The Order indicates Plaintiffs may be willing to consolidate all cases pending in the Western District with those in the Eastern District, although Defendants may not be amenable to same. That did not occur and this case remains stayed. In the interim, an Order was issued in another of the coastal cases pending in the Eastern District of Louisiana lifting the stay and setting a schedule for briefing for plaintiffs’ motion to remand (Parish of Plaquemines v. Riverwood Production Company, et al., No. 2:18-cv-05217, Eastern District of Louisiana). Judge Martin L. C. Feldman is assigned to the Riverwood case and he will be the first Judge in the Eastern District to decide on the remand, and presumably the Judges assigned to other cases, including this one, will follow his decision as relevant and appropriate. Oral argument on the motion to remand in the Riverwood case has been repeatedly continued, and is currently scheduled for April 10, 2019. Based on the lack of ruling in the Auster case as reported below, it is unknown whether hearing in the Riverwood case will be held on that date. It is impossible to predict at this time whether this second removal will keep the case in federal court. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on our consolidated financial statements.

 

Cameron Parish vs. BEPCO LP, et al & Cameron Parish vs. Alpine Exploration Companies, Inc., et al.

 

The Parish of Cameron, Louisiana, filed a series of lawsuits against approximately 190 oil and gas companies alleging that the defendants, including Davis Petroleum Acquisition Corp. (“Davis”), have failed to clear, revegetate, detoxify, and restore the mineral and production sites and other areas affected by their operations and activities within certain coastal zone areas to their original condition as required by Louisiana law, and that such defendants are liable to Cameron Parish for damages under certain Louisiana coastal zone laws for such failures; however, the amount of such damages has not been specified. Two of these lawsuits, originally filed February 4, 2016 in the 38th Judicial District Court for the Parish of Cameron, State of Louisiana, name Davis as defendant, along with more than 30 other oil and gas companies. Both cases have been removed to federal district court for the Western District of Louisiana. We deny these claims and intend to vigorously defend them. Davis has become a party to the Joint Defense and Cost Sharing Agreements for these cases. Motions to remand were filed and the Magistrate Judge recommended that the cases be remanded. We were advised that the new District Judge assigned to these cases is Judge Terry A. Doughty, and on May 9, 2018, Judge Doughty agreed with the Magistrate Judge’s recommendation and the cases were remanded to the 38th Judicial District Court, Cameron Parish, Louisiana. The cases were removed again on other grounds on May 23, 2018. On May 25, 2018, a Motion was filed on behalf of certain defendants with the United States Judicial Panel for Multi District Litigation (“JPMDL”) for consolidated proceedings for all 41 pending cases filed in Louisiana with claims that are substantially the same as those in these cases. A 42nd case has been added as a “tag-along”. In the interim, plaintiffs timely filed their Motion to Remand in the cases. Hearing on the Motion before the JPMDL was held on July 26, 2018 in Santa Fe, New Mexico, and the JPMDL denied centralization by Order dated July 31, 2018. The Order indicates Plaintiffs may be willing to consolidate all cases pending in the Western District with those in the Eastern District, although Defendants may not be amenable to same. That did not occur. On October 1, 2018, all of the coastal cases pending in the Western District of Louisiana, including these cases, were re-assigned to the newly appointed District Judge, Judge Robert R. Summerhays. On August 29, 2018, Magistrate Judge Kay signed an Order providing for staged briefing on the plaintiffs’ motion(s) to remand in all the coastal cases pending in the Western District, with the lowest numbered case (Parish of Cameron v. Auster, No. 18-677, Western District of Louisiana) to proceed first. In response to Defendants’ request for oral argument in the Auster case, Judge Kay issued an electronic Order on October 18, 2018, denying that request and further stating, “The issues have been thoroughly briefed and we do not find at this time that oral argument would be helpful.” As noted above, Magistrate Judge Kay previously recommended remand of these cases, which recommendation was adopted by the District Judge then assigned to the cases. Magistrate Judge Kay issued her Report and Recommendations recommending remand based on the timeliness of the second removal. Objections and replies were filed to the same and the District Judge now assigned to the cases granted and held oral argument on the objections to Magistrate Judge Kay’s Report and Recommendations on January 16, 2019. The District Judge has not yet ruled It is impossible to predict at this time whether this second removal will keep the cases in federal court. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on our consolidated financial statements.

 

 

Louisiana, et al. Escheat Tax Audits

The States of Louisiana, Texas, Minnesota, North Dakota and Wyoming have notified us that they will examine our books and records to determine compliance with each of the examining state’s escheat laws. The review is being conducted by Discovery Audit Services, LLC. We have engaged Ryan, LLC to represent us in this matter. The exposure related to the audits is not currently determinable and therefore, no liability has been recorded on our consolidated financial statements.

Louisiana Severance Tax Audit

 

The State of Louisiana, Department of Revenue, notified Exploration that it was auditing Exploration’s calculation of its severance tax relating to Exploration’s production from November 2012 through March 2016. The audit relates to the Department of Revenue’s recent interpretation of long-standing oil purchase contracts to include a disallowable “transportation deduction,” and thus to assert that the severance tax paid on crude oil sold during the contract term was not properly calculated.  The Department of Revenue sent a proposed assessment in which they sought to impose $476,954 in additional state severance tax plus associated penalties and interest.   Exploration engaged legal counsel to protest the proposed assessment and request a hearing.  Exploration then entered a Joint Defense Group of operators challenging similar audit results.  Since the Joint Defense Group is challenging the same legal theory, the Board of Tax Appeals proposed to hear a motion brought by one of the taxpayers (Avanti) that would address the rule for all through a test case.  Exploration’s case has been stayed pending adjudication of the test case. The hearing for the Avanti test case was held on November 7, 2017, and on December 6, 2017, the Board of Tax Appeals rendered judgment in favor of the taxpayer in the first of these cases. The Department of Revenue filed an appeal to this decision on January 5, 2018. The Board of Tax Appeals case record has been lodged at the Louisiana Third Circuit Court of Appeal in the Avanti test case. Oral argument was held at the Third Circuit on Tuesday, February 26, 2019, and a decision should be issued sometime in the next six to eight weeks. All other Board of Tax Appeals cases are stayed pending the final decision in the Avanti case. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on our consolidated financial statements.

 

Louisiana Department of Wildlife and Fisheries

 

We received notice from the Louisiana Department of Wildlife and Fisheries (“LDWF”) in July 2017 stating that Exploration has open Coastal Use Permits (“CUPs”) located within the Louisiana Public Oyster Seed Grounds dating back from as early as November 1993 and through a period ending in November 2012.  The majority of the claims relate to permits that were filed from 2000 to 2005.  Pursuant to the conditions of each CUP, LDWF is alleging that damages were caused to the oyster seed grounds and that compensation of an aggregate amount of approximately $500,000 is owed by the Company.  We are currently evaluating the merits of the claim, are reviewing the LDWF analysis, and have now requested that the LDWF revise downward the amount of area their claims of damages pertain to. At this point in the regulatory process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on our consolidated financial statements.

 

Miami Corporation – South Pecan Lake Field Area P&A

 

We, along with several other exploration and production companies in the chain of title, received letters in June 2017 from representatives of Miami Corporation demanding the performance of well plugging and abandonment, facility removal and restoration obligations for wells in the South Pecan Lake Field Area, Cameron Parish, Louisiana. Apache is one of the other companies in the chain of title, and after taking a field tour of the area, has sent to us, along with BP and other companies in the chain of title, a proposed work plan to comply with the Miami Corporation demand. We are currently evaluating the merits of the claim and awaiting further information. At this point in the process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on our consolidated financial statements.

 

 

John Hoffman v. Yuma Exploration & Production Company, Inc., et al

 

This lawsuit, filed on June 15, 2018 in Livingston Parish, Louisiana, against us, Precision Drilling and Dynamic Offshore relates to a slip and fall injury to Mr. Hoffman that occurred on August 28, 2017. Mr. Hoffman was apparently an employee of a subcontractor of a contractor performing services for us. Precision has made demand for defense and indemnity against us based on a contract entered into between the parties. The defense and indemnity demand is being contested, primarily on the grounds that the defense and indemnity obligation is barred by the Louisiana Anti-Indemnity Act. We believe that our contractor is responsible for injuries to employees of the contractor or subcontractor and that their insurance coverage, or insurance coverage maintained by us, should cover damages awarded to Mr. Hoffman. We have notified our insurance carrier of the lawsuit. Counsel believes that the claim will be successfully defended, but even if the defense and indemnity claim is legally enforceable, there is sufficient insurance in place to cover the exposure. Accordingly, the defense and indemnity claim does not represent any direct material exposure to us.

 

Hall-Degravelles, L.L.C. v. Cockrell Oil Corporation, et al

Avalon Plantation, Inc., et al v. Devon Energy Production Company, L.P., et al

Avalon Plantation, Inc., et al v. American Midstream, et al

 

We, as a successor in interest from another company years ago, along with 41 other companies in the chain of title, were named as a defendant in this lawsuit brought in St. Mary’s Parish, Louisiana on July 9, 2018. The substance of each of the petitions is virtually identical. In each case, the plaintiff(s) are seeking to recover damages to their property resulting from “oil and gas exploration and production activities.” The cited grounds for these actions include La. R.S. 30:29 (providing for restoration of property affected by oilfield contamination) and C.C. art. 2688 (notification by the lessee to the lessor when leased property is damaged). The plaintiffs are attempting to have these three cases consolidated. A hearing on motion to consolidate was held on January 15, 2019. At that time, Judge Sigur stated from the bench that he did not have sufficient information to order consolidation. A judgment to that effect has been submitted to the judge for signature. These cases are in the very early stages. At this point, not all of the named defendants have filed responsive pleadings. All of the defendants who have responded at this point have, inter alia, filed exceptions of vagueness due to the lack of specificity in the petitions which makes it impossible to determine what action(s) any individual defendant may have performed which would result in liability to the plaintiffs. The only exceptions that have been set for hearing are those jointly filed by XTO Energy, Inc., Exxon Mobil Oil Corporation and Exxon Mobil Corporation. We sold the leases that appear to be involved in this litigation to Hilcorp Energy I, L.P. (“Hilcorp”), with an effective date of September 1, 2016. The conveyance includes an indemnity provision which appears to transfer liability for this type of damage to Hilcorp, and at some point it will be necessary to invoke this indemnity. We have notified our insurance carrier of the claim but believe that the suit is without merit. No evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made at this early stage, therefore no liability has been recorded on our consolidated financial statements.

 

Vintage Assets, Inc. v. Tennessee Gas Pipeline, L.L.C., et al

 

On September 10, 2018, we received a Demand for Defense and Indemnity from High Point Gas Gathering, L.P. (“HPGG”) pursuant to the 2010 Purchase and Sale Agreement between Texas Southeastern Gas Gathering Company, et al and HPGG, et al. The demand related to a judgment and permanent injunction entered against HPGG and three other defendants on May 4, 2018 in the above referenced matter in the U.S. District Court in the Eastern District of Louisiana. We received a letter dated October 30, 2018 from HPGG informing us that the May 4, 2018 judgment had been vacated. No evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made at this early stage, therefore, no liability has been recorded on our consolidated financial statements.

 

Texas General Land Office (“GLO”)

 

On February 21, 2019, the GLO notified us that it would be conducting an audit of oil and gas production and royalty revenue for the period of September 2012 to August 2017 related to three of our leases located in Chambers County, Texas and four of our leases located in Jefferson County, Texas. The exposure related to the audit is not currently determinable and therefore, no liability has been recorded on our consolidated financial statements.

 

Sam Banks v. Yuma Energy, Inc.

 

By letter dated March 27, 2019, the Company’s Board of Directors notified Sam L. Banks that it was terminating him as Chief Executive Officer of the Company pursuant to the terms of his amended and restated employment agreement dated April 20, 2017 (the “Employment Agreement”). Mr. Banks continues to serve on the board of directors of the Company. Mr. Banks also holds approximately 10.9% of the outstanding common stock of the Company and approximately 9.4% of the outstanding voting securities of the Company on a fully diluted, as converted basis. On March 28, 2019, Mr. Banks filed a petition (the “Petition”) in the 189th Judicial District Court of Harris County, Texas, naming the Company as defendant. The Petition alleges a breach of the Employment Agreement and seeks severance benefits in the amount of approximately $2.15 million. The Company intends to vigorously defend the lawsuit.

 

 

Not applicable.

 

 

PART II

 

 

Market Prices and Holders

 

Our common stock is listed for trading on the NYSE American under the symbol “YUMA.” The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock on the NYSE American.

 

	Common Stock Price
	High	Low
Quarter Ended
2017
March 31	$3.91	$2.06
June 30	$3.17	$0.81
September 30	$3.10	$0.77
December 31	$1.43	$0.85
2018
March 31	$1.83	$1.03
June 30	$1.54	$0.33
September 30	$0.74	$0.16
December 31	$0.48	$0.09

 

As of March 29, 2019, there were approximately 108 stockholders 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 stockholders 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, our Credit Agreement does not permit us to pay dividends on our common stock.

 

 

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.

 

 

 

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.”

 

Recent developments

 

Senior Credit Agreement and Going Concern

 

The factors and uncertainties described below, as well as other factors which include, but are not limited to, declines in our production, reduction of personnel, our failure to establish commercial production on our Permian properties, and our substantial working capital deficit of approximately $37.0 million, raise substantial doubt about our ability to continue as a going concern. The Consolidated Financial Statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The Consolidated Financial Statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

 

On October 26, 2016, the Company and three of its subsidiaries, as the co-borrowers, entered into a credit agreement providing for a $75.0 million three-year senior secured revolving credit facility (the “Credit Agreement”) with Société Générale (“SocGen”), as administrative agent, SG Americas Securities, LLC, as lead arranger and bookrunner, and the lenders signatory thereto (collectively with SocGen, the “Lender”).

 

The borrowing base of the credit facility was $34.0 million as of December 31, 2018, and the Company was and is fully drawn under the credit facility leaving no availability on the line of credit. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of our assets.

 

The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and distributions or repurchase our capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable, and engage in certain transactions with affiliates.

 

In addition, the Credit Agreement requires us to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 on the last day of each quarter, a ratio of total debt to earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) of not greater than 3.5 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and a ratio of EBITDAX to interest expense of not less than 2.75 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and cash and cash equivalent investments together with borrowing availability under the Credit Agreement of at least $4.0 million. The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral.

 

 

At December 31, 2018, we were not in compliance under the credit facility with our (i) total debt to EBITDAX covenant for the trailing four quarter period, (ii) current ratio covenant, (iii) EBITDAX to interest expense covenant for the trailing four quarter period, (iv) the liquidity covenant requiring us to maintain unrestricted cash and borrowing base availability of at least $4.0 million, and (v) obligation to make an interest only payment for the quarter ended December 31, 2018. In addition, we currently are not making payments of interest under the credit facility and anticipate future non-compliance under the credit facility going forward. Due to this non-compliance, as well as the credit facility maturity in 2019, we classified our entire bank debt as a current liability in our financial statements as of December 31, 2018. On October 9, 2018, we received a notice and reservation of rights from the administrative agent under the Credit Agreement advising that an event of default has occurred and continues to exist by reason of our noncompliance with the liquidity covenant requiring us to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the Lender may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the Lender has not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but may exercise one or more of these remedies in the future. We have commenced discussions with the Lender concerning a forbearance agreement; however, there can be no assurance that the Lender and us will come to any agreement regarding a forbearance agreement or waiver of the events of default. As required under the Credit Agreement, we previously entered into hedging arrangements with SocGen and BP Energy Company (“BP”) pursuant to International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”). On March 14, 2019, we received a notice of an event of default under our ISDA Agreement with SocGen (the “SocGen ISDA”). Due to the default under the ISDA Agreement, SocGen unwound all of our hedges with them. The notice provides for a payment of approximately $347,129 to settle our outstanding obligations thereunder related to SocGen’s hedges. On March 19, 2019, we received a notice of an event of default under our ISDA Agreement with BP (the “BP ISDA”). Due to the default under the ISDA Agreement, BP also unwound all of our hedges with them. The notice provides for a payment of approximately $775,725 to settle our outstanding obligations thereunder related to BP’s hedges.

 

Sale of Certain Non-Core Oil and Gas Properties

 

On August 20, 2018, we sold our 3.1% leasehold interest consisting of 9.8 net acres in one section in Eddy County, New Mexico for $127,400. On October 23, 2018, we sold substantially all of our Bakken assets in North Dakota for approximately $1.16 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $15,200. The Bakken assets represented approximately 12 barrels of oil equivalent per day of our production in the third quarter of 2018. On October 24, 2018, we sold certain deep rights in undeveloped acreage located in Grady County, Oklahoma for approximately $120,000. Proceeds of $1.0 million from these non-core asset sales were applied to the repayment of borrowings under the credit facility in October 2018, bringing the current outstanding balance and borrowing base under the credit facility to $34.0 million, with the balance of the proceeds used for working capital purposes.

 

Recent Entry into PSA on our California Properties

 

 An Asset Purchase and Sale Agreement dated March 21, 2019, was executed on behalf of Pyramid Oil, LlC and Yuma Energy, Inc. (Sellers) and an undisclosed buyer (buyer) covering the sale of all of Seller's assets in Kern County, California. The purchase price for the sale is $2.1 million and the effective date is April 1, 2018. The parties expect to close the transaction by April 26, 2019. As additional consideration for the sale of the assets, if WTI Index for oil equals or exceeds $65  in the six months following closing and maintains that average for twelve consecutive months then Buyer shall pay to the Seller $250,000. Upon Cosing, we anticipate that the proceeds will be applied to the repayment of borrowings under the credit facility and/or working capital; however, there can be no assurance that the transaction will close.

 

Preferred Stock

 

As of December 31, 2018, we had 2,041,241 shares of our Series D preferred stock outstanding with an aggregate liquidation preference of approximately $22.6 million and a conversion price of $6.5838109 per share. The conversion price was adjusted from $11.0741176 per share to $6.5838109 per share as a result of our common stock offering that closed in October 2017. As a result, if all of our outstanding shares of Series D preferred stock were converted into common stock, we would need to issue approximately 3.4 million shares of common stock. The Series D preferred stock is paid dividends in the form of additional shares of Series D preferred stock at a rate of 7% per annum.

 

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, 2018 and 2017, and the average sales price per unit sold.

 

	Years Ended December 31,
	2018	2017
Production volumes:
Crude oil and condensate (Bbls)	171,590	250,343
Natural gas (Mcf)	2,094,984	3,085,613
Natural gas liquids (Bbls)	100,234	131,155
Total (Boe) (1)	620,988	895,767
Average prices realized:
Crude oil and condensate (per Bbl)	$67.40	$50.32
Natural gas (per Mcf)	$3.19	$3.05
Natural gas liquids (per Bbl)	$32.19	$26.08

 

 

Revenues

 

The following table presents our revenues for the years ended December 31, 2018 and 2017.

 

	Years Ended December 31,
	2018	2017
Sales of natural gas and crude oil:
Crude oil and condensate	$11,565,706	$12,596,983
Natural gas	6,678,666	9,425,676
Natural gas liquids	3,226,721	3,420,942
Total revenues	$21,471,093	$25,443,601

 

 

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 WTI and adjusted to LLS or HLS. 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 31.5%, or 78,753 Bbls, lower for the year ended December 31, 2018 compared to crude oil volumes sold during the year ended December 31, 2017. This decrease was primarily due to a decrease in the El Halcón Field (15,300 Bbls), which was divested during the second quarter of 2017, and declines in the Cameron Canal Field (12,942 Bbls), the La Posada wells (11,097 Bbls), Livingston Field (9,714 Bbls), Raccoon Island (6,284 Bbls), and the Chalktown Field (4,446 Bbls). Realized crude oil prices experienced a 33.9% increase from the year ended December 31, 2017 to the year ended December 31, 2018.

 

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, 2018 compared to the year ended December 31, 2017, we experienced a 32.1%, or 990,629 Mcf decrease in natural gas volumes sold, primarily due to declines in volumes from the La Posada wells (580,315 Mcf), the Cameron Canal Field (281,052 Mcf), and the Lac Blanc Field (70,245 Mcf). Realized natural gas prices experienced a 4.6% increase from the prior year ended December 31, 2017.

 

For the year ended December 31, 2018 compared to the year ended December 31, 2017, we experienced a 23.6%, or 30,921 Bbl decrease in natural gas liquids volumes sold primarily due to declines in volumes from the La Posada Wells (15,510 Bbls), the Lac Blanc Field (6,894 Bbls), and the Chalktown Field (4,967 Bbls). Realized natural gas liquids prices experienced a 23.4% increase from the prior year ended December 31, 2017.

 

Expenses

 

Lease Operating Expenses

 

Our lease operating expenses (“LOE”) and LOE per Boe for the years ended December 31, 2018 and 2017, are set forth below:

 

	Years Ended December 31,
	2018	2017
Lease operating expenses	$7,077,838	$6,715,337
Severance, ad valorem taxes and marketing	3,483,626	4,321,976
Total LOE	$10,561,464	$11,037,313
LOE per Boe	$17.01	$12.32
LOE per Boe without severance, ad valorem taxes and marketing	$11.40	$7.50

 

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 capital workovers.

 

The 4.3% decrease in total LOE for the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to a decrease in processing of $646,844 offset by an increase in LOE of $209,846 as a result of higher liability insurance, facility and non-capital workover costs. LOE per Boe increased by 38.1% for the same period generally due to lower production when compared to the prior year.

 

General and Administrative Expenses

 

Our general and administrative (“G&A”) expenses for the years ended December 31, 2018 and 2017, are summarized as follows:

 

	Years Ended December 31,
	2018	2017
General and administrative:
Stock-based compensation	$582,344	$2,381,365
Capitalized	-	-
Net stock-based compensation	582,344	2,381,365
Other	6,871,529	8,541,291
Capitalized	(733,199)	(1,606,910)
Net other	6,138,330	6,934,381
Net general and administrative expenses	$6,720,674	$9,315,746

 

G&A Other primarily consists 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. During the second half of 2018, we stopped capitalizing overhead due to the departure of our exploration staff and a lack of development activity.

 

 

For the year ended December 31, 2018, net G&A expenses were 27.9%, or $2,595,072, less than the amount for the prior year ended December 31, 2017. The decrease in G&A expenses was primarily attributed to a decrease in accounting and audit fees of $221,791, a decrease in consulting fees of $121,526, a decrease in directors’ fees of $127,500, a decrease in salaries and stock compensation of $443,076 and $1,799,021, respectively, and a decrease in costs associated with the Company’s acquisition of Davis of $255,654. These reductions were offset by an increase in termination benefits of $169,825 and an increase in office rent of $224,454 primarily related to amounts of rent capitalized in 2017 compared to 2018.

 

Depreciation, Depletion and Amortization

 

Our depreciation, depletion and amortization (“DD&A”) for oil and natural gas properties (excluding DD&A related to other property, plant and equipment) for the years ended December 31, 2018 and 2017, is summarized as follows:

 

	Years Ended December 31,
	2018	2017
DD&A	$8,427,599	$10,724,967
DD&A per Boe	$13.57	$11.97

 

DD&A expense decreased $2,297,368, or 21.4%, for the year ended December 31, 2018 compared to the year ended December 31, 2017. The decrease resulted primarily from decreased production in 2018. The rate of DD&A per Boe in 2018 increased due to us writing off our PUDs during the year as a result of our liquidity and the uncertainty of our ability to fund their future development.

 

Impairment of Oil and Natural Gas Properties

 

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling,” based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment of $7.05 million and  $-0- for the years ended December 31, 2018 and 2017, respectively. The write-off of our Proved Undeveloped Reserves due to the uncertainty of our ability to fund their development was the primary reason for the ceiling impairment in 2018. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

 

Interest Expense

 

Our interest expense for the years ended December 31, 2018 and 2017, is summarized as follows:

 

	Years Ended December 31,
	2018	2017
Interest expense	$2,447,426	$2,052,498
Interest capitalized	(133,772)	(317,691)
Net	$2,313,654	$1,734,807
Bank debt	$34,000,000	$27,700,000

 

 

See Note 16 – Debt and Interest Expense in the Notes to Consolidated Financial Statements included in this report for additional information on the credit agreement and interest expense.

 

 

 

Income Tax Expense

 

The following summarizes our income tax expense (benefit) and effective tax rates for the years ended December 31, 2018 and 2017:

 

	Years Ended December 31,
	2018	2017
Consolidated net income (loss) before income taxes	$(15,554,789)	$(5,392,768)
Income tax expense (benefit)	$-	$-
Effective tax rate	(0.00%)	(0.00%)

 

 

Liquidity and Capital Resources

 

The factors and uncertainties described below raise substantial doubt about our ability to continue as a going concern. Our primary and potential sources of liquidity include cash on hand, cash from operating activities, 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 and we are currently unhedged on our oil and gas production. As disclosed in our Consolidated Financial Statements, we incurred net losses attributable to common shareholders of $17.1 million and $6.8 million for the years ended December 31, 2018 and 2017, respectively. At December 31, 2018, our total current liabilities of $44.2 million exceed our total current assets of $7.2 million. Additionally, we are in violation of our debt covenants, have stopped paying interest under our credit facility, have extremely limited liquidity and have suffered recurring losses from operations. In addition, we are subject to a number of factors that are beyond our control, including commodity prices, our bank’s determination of our borrowing base, production declines and other factors that could affect our liquidity and ability to continue as a going concern.

 

We have recently experienced a number of mechanical issues on well sites including the Lac Blanc #2, and others that are impacting our rates of production and hence having a negative impact on the operating cash flow of the company. Field level operating cash flows prior to these issues were approximately $750,000 per month and currently projected to be $400,000 assuming no repairs take place.  We are planning on certain repairs costing an estimated $500,000 that will return field level operating cash flow to an estimated $600,000 per month.  While we anticipate returning a number of these wells to production, for others, like the Lac Blanc LP #2, repair cost estimates could be significant and there is no assurance we can fund the work based on our current severe liquidity constraints, which will result in a loss of an estimated $150,000 per month of field level cash flow.  Actual results could differ from these estimates, and the differences could be significant, as we continue to evaluate.

 

We are currently in default under our credit facility due to non-compliance with our financial covenants and failure to pay interest. As of December 31, 2018, we had fully drawn the $34.0 million available under our credit facility. On October 9, 2018, we received a notice and reservation of rights from the administrative agent under our Credit Agreement advising that an event of default has occurred and continues to exist by reason of our noncompliance with the liquidity covenant requiring us to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the lenders may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the lenders have not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but they may exercise one or more of these remedies in the future. We have commenced discussions with the lenders under the Credit Agreement concerning a forbearance agreement or waiver of the events of default; however, there can be no assurance that we and the lenders will come to any agreement regarding a forbearance or waiver of the events of default.

 

We initiated several strategic alternatives to mitigate our limited liquidity (defined as cash on hand and undrawn borrowing base), our financial covenant compliance issues, and to provide us with additional working capital to develop our existing assets.

 

During the first quarter of 2019, we agreed to sell our Kern County, California properties for $2.1 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $864,000, and received a non-refundable deposit of $150,000. As additional consideration for the sale of the assets, if WTI Index for oil equals or exceeds $65 in the six months following closing and maintains that average for twelve consecutive months then Buyer shall pay to the Seller $250,000. As additional consideration for the sale of the assets, if WTI Index for oil equals or exceeds $65 in six months following closing and maintains that average for twelve cosecutive months then Buyer shall pay to the seller $250,000. Upon closing, we anticipate that the proceeds will be applied to the repayment of borrowings under the credit facility and/or working capital; however, there can be no assurance that the transaction will close.

 

On August 20, 2018, we sold our 3.1% leasehold interest consisting of 9.8 net acres in one section in Eddy County, New Mexico for $127,400. On October 23, 2018, we sold substantially all of our Bakken assets in North Dakota for approximately $1.16 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $15,200. The Bakken assets represent approximately 12 barrels of oil equivalent per day of our production in the third quarter. On October 24, 2018, we sold certain deep rights in undeveloped acreage located in Grady County, Oklahoma for approximately $120,000. Proceeds of $1.0 million from these non-core asset sales were applied to the repayment of borrowings under the credit facility in October 2018, bringing the current outstanding balance and borrowing base under the credit facility to $34.0 million, with the balance of the proceeds used for working capital purposes.

 

 

We continue to reduce our personnel, consultants, and other non-essential services and expenses in an effort to reduce our general and administrative costs, as well as curtailing our estimated capital expenditures planned for 2019. We have reduced our personnel by eleven employees since December 31, 2017, a 32% decrease. This brings our headcount to 23 employees as of December 31, 2018.

 

On October 22, 2018, we retained Seaport Global Securities LLC (“Seaport”) as our exclusive financial advisor and investment banker in connection with identifying and potentially implementing various strategic alternatives to improve our liquidity issues and the possible disposition, acquisition or merger of the Company or our assets. In addition, prior to the retention of Seaport, we retained Energy Advisors Group to sell select properties of the Company, including Main Pass 2 & 4, and our properties in California and Livingston Parish, Louisiana.

 

We plan to take further steps to mitigate our limited liquidity, which may include, but are not limited to, further reducing or eliminating capital expenditures; selling additional assets; further reducing general and administrative expenses; seeking merger and acquisition related opportunities; and potentially raising proceeds from capital markets transactions, including the sale of debt or equity securities. There can be no assurance that the exploration of strategic alternatives will result in a transaction or otherwise improve our limited liquidity.

 

Cash Flows

 

Our net increase (decrease) in cash for the years ended December, 31, 2018 and 2017, is summarized as follows:

 

	Years Ended December 31,
	2018	2017
Cash flows provided by (used in) operating activities	$3,819,172	$3,246,058
Cash flows used in investing activities	(8,236,001)	(3,419,840)
Cash flows provided by (used in) financing activities	5,913,958	(3,314,541)
Net increase (decrease) in cash	$1,497,129	$(3,488,323)

 

Cash Flows From Operating Activities

 

Net cash provided by operating activities was $3,819,172 for the year ended December 31, 2018 compared to $3,246,058 in cash provided during the same period in 2017.  This increase was primarily caused by the $176,648 increase in accounts payable and other current and non-current liabilities in 2018 compared to the $2,462,040 decrease in accounts payable and other current and non-current liabilities in 2017.  Sales of natural gas and crude oil were down $3,972,508 in 2018 since the decrease in production was greater than the increase in prices.  Lease operating and general & administrative expenses were down $1,546,900 including the $275,000 credit for the deposit forfeiture. Funds were also used for a $590,709 in the 2018 settlement of asset retirement obligations compared to $1,045,257 in 2017. 

 

One of the primary sources of variability in our cash flows from operating activities is fluctuations in commodity prices.  Sales volume changes also impact cash flow.  Our cash flows from operating activities are also dependent on the costs related to continued operations.

 

Cash Flows From Investing Activities

 

Net cash used in investing activities was $8,236,001 for the year ended December 31, 2018 compared to $3,419,840 in cash used during the same period in 2017.  During the year ended December 31, 2018, we had a total of $8,189,465 in oil and natural gas investing activities.  Of that, $1,930,814 was related to the completion of the State 320, $355,943 for the workover on the Fremaux SWD, and $4,026,996 for the reduction in capital expenditures in accounts payable.  In addition, $733,199 was capitalized G&A related to land, geological and geophysical costs. These amounts were offset by $2,372,767 related to proceeds from the sale of oil and natural gas properties.  The settlements of commodity derivatives resulted in a $2,419,303 use of cash.  

 

 

In 2017, we had a total of $1,894,685 related to the drilling of the Weyerhaeuser 14 #1, $1,723,565 related to the recompletion of the State Lease 14564 #4 well, $1,016,002 related to the SL 18090 #2 well to establish production from the SIPH-D1 zone, $2,165,139 was for the drilling of the Jameson #1 SWD and $2,321,794 was spent on lease acquisition costs related to our Permian Basin project. These amounts were offset by $5,400,563 related to proceeds from the sale of oil and natural gas properties, and $1,238,341 related to settlements of commodity derivatives.  In addition, $1,606,910 was capitalized G&A related to land, geological and geophysical costs.

 

Cash Flows From Financing Activities

 

During the year ended December 31, 2018, we had net cash provided in financing activities of $5,913,958.  Of that amount, $6,300,000 (net) was borrowed under our credit facility and $91,829 (net) was borrowed under our insurance financing. These amounts were offset by $413,821 for treasury stock repurchases and $64,050 for common stock offering costs.

 

At December 31, 2018, we had no remaining availability on our $34,000,000 credit facility.

 

We had a cash balance of $1,634,492 at December 31, 2018.

 

Commodity Derivative 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 commodity derivative 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, 2018		December 31, 2017
	Oil	Natural Gas	Oil	Natural Gas
Assets
Current	$1,005,012	$26,601	$-	$-
Noncurrent	$-	$98,530	$-	$-
Liabilities
Current	$(82,450)	$(198,005)	$(1,198,307)	$295,304
Noncurrent	$-	$(85,502)	$(319,104)	$(17,302)

 

Assets and liabilities are netted within each commodity on the Consolidated Balance Sheets 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 12 – Commodity Derivative Instruments.

 

The fair market value of our commodity derivative contracts in place at December 31, 2018 and December 31, 2017 were net assets of $764,186 and net liabilities $1,239,409, respectively.

 

As required under the Credit Agreement, we previously entered into hedging arrangements with SocGen and BP Energy Company (“BP”) pursuant to International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”). On March 14, 2019, we received a notice of an event of default under our ISDA Agreement with SocGen (the “SocGen ISDA”). Due to the default under the ISDA Agreement, SocGen unwound all of our hedges with them. The notice provides for a payment of approximately $347,129 to settle our outstanding obligations thereunder related to SocGen’s hedges. On March 19, 2019, we received a notice of an event of default under our ISDA Agreement with BP (the “BP ISDA”). Due to the default under the ISDA Agreement, BP also unwound all of our hedges with them. The notice provides for a payment of approximately $775,725 to settle our outstanding obligations thereunder related to BP’s hedges.

 

 

See Part II, Item 8. Notes to the Consolidated Financial Statements, Note 12 – Commodity Derivative Instruments, for additional information on our commodity derivatives.

 

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.

 

Assets Held for Sale

 

The fair values of property, plant and equipment, classified as assets held for sale and related impairments, which are calculated using Level 3 inputs, are discussed in Part II, Item 8. Notes to the Consolidated Financial Statements, Note 3 – Significant Accounting Policies.

 

Commitments and Contingencies

 

We had the following contractual obligations and commitments as of December 31, 2018:

 

		Liability for			Asset
		Commodity	Throughput	Operating	Retirement
	Debt (1)	Derivatives (2)	Commitment (3)	Leases	Obligations	Total
2019	$34,742,953	$280,455	$344,327	$532,147	$128,539	$36,028,421
2020	-	85,502	86,082	520,297	604,057	1,295,938
2021	-	-	-	524,044	675,354	1,199,398
2022	-	-	-	530,990	661,342	1,192,332
2023	-	-	-	351,392	434,335	785,727
Thereafter	-	-	-	-	8,768,231	8,768,231
Totals	$34,742,953	$365,957	$430,409	$2,458,870	$11,271,858	$49,270,047