UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

(Mark One)

☒ ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2015

 

or

 

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

 

For the transition period from __________ to __________

 

Commission file number 005-86157

 

ARABELLA EXPLORATION, INC.

(Exact name of registrant as specified in its charter)

 

Cayman Islands		98-1162608
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

 

509 Pecan Street, Suite 200
Fort Worth, Texas 76102

(Address of principal executive offices)

 

432 897-4755
(Registrant’s telephone number, including area code)

 

Securities registered under Section 12(b) of the Act:	None
Securities registered under Section 12(g) of the Act:	Units Ordinary Shares, $0.001 par value Ordinary Share Purchase Warrants

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒ No ☐

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☒

 

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

 

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

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

 

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2015: $3,884,426.

 

As of April 13, 2016, the registrant had 5,020,303 outstanding shares of common stock.

 

DOCUMENTS INCORPORATED BY REFERENCE: None

 

Forward-Looking Statements

 

This Annual Report on Form 10-K (“Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (“Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”). All statements other than statements of historical fact are “forward-looking statements” for purposes of this Report, including any projections of earnings, revenue or other financial items, any statements regarding the plans and objectives of management for future operations, any statements concerning proposed new products or services, any statements regarding future economic conditions or performance, any statements regarding expected benefits from any transactions and any statements of assumptions underlying any of the foregoing. In some cases, forward-looking statements can be identified by the use of terminology such as “may,” “will,” “expects,” “plans,” “anticipates,” “estimates,” “potential” or “continue,” or the negative thereof or other comparable terminology. Although we believe that the expectations reflected in the forward-looking statements contained in this Report are reasonable, there can be no assurance that such expectations or any of the forward-looking statements will prove to be correct, and actual results could differ materially from those projected or assumed in the forward-looking statements. Thus, investors should refer to and carefully review information in future documents the Company files with the Securities and Exchange Commission (“SEC”). Our future financial condition and results of operations, as well as any forward-looking statements, are subject to inherent risk and uncertainties, including, but not limited to, the risk factors set forth in “Part I, Item 1A – Risk Factors” below and for the reasons described elsewhere in this Report. All forward looking statements and reasons why results may differ included in this Report are made as of the date hereof, and we do not intend to update any forward-looking statements except as required by law or applicable regulations. Except where the context otherwise requires, in this Report, the “Company,” “Arabella,” “we,” “us” and “our” refer to Arabella Exploration, Inc., a Cayman Islands company, and, where appropriate, its subsidiaries.

 

 

ARABELLA EXPLORATION, INC.

 

INDEX

 

		Page
PART I
Items 1. and 2.	Business and Properties	1
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	33
Item 3.	Legal Proceedings	33
Item 4.	Mine Safety Disclosures	33
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	35
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 8.	Financial Statements and Supplementary Data	43
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	44
Item 9A.	Controls and Procedures	44
Item 9B.	Other Information	44
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	45
Item 11.	Executive Compensation	47
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
Item 13.	Certain Relationships and Related Transactions and Director Independence	52
Item 14.	Principal Accountant Fees and Services	52
PART IV
Item 15.	Exhibits	53

 

 

GLOSSARY OF OIL AND NATURAL GAS TERMS:

 

The following is a description of the meanings of some of the oil and natural gas industry terms used throughout this report:

 

3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

 

Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

 

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

 

Bbls/d. Bbls per day.

 

Bcf. One billion cubic feet of natural gas.

 

BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. BOE is commonly used by oil and gas companies in their financial statements as a way of combining oil and natural gas reserves and production into a single measure.

 

BOE/d. BOE per day.

 

Btu or British thermal unit. The quantity of heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

 

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

 

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface temperature and pressure.

 

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

 

Development capital. Expenditures to obtain access to proved reserves and to construct facilities for producing, treating, and storing hydrocarbons.

 

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

 

Deviated well. A well purposely deviated from the vertical using controlled angles to reach an objective location other than directly below the surface location.

 

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

 

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of operation. For a complete definition of “economically producible”, refer to the SEC’s Regulation S- X, Rule 4,- 10(a)(10).

 

EUR. Estimated ultimate recovery, the sum of gross reserves remaining as of a given date and the cumulative production as of that date.

 

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

 

F&D Costs. Finding and development costs, capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

 

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface area and the underground productive formations. For a complete definition of “field”, refer to the SEC’s Regulation S- X, Rule 4,- 10(a)(15).

 

 

Formation. A layer of rock that has distinct characteristics that differ from nearby rock.

 

Fracturing or fracing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

 

GAAP. Accounting principles generally accepted in the United States.

 

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

 

Held by production acreage. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

 

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.

 

LOE. Lease operating expense, all direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

 

MBbls. One thousand barrels.

 

MBO. One thousand barrels of crude oil, condensate or NGLs.

 

Mcf. One thousand cubic feet of natural gas.

 

Mcf/d. Mcf per day.

 

MBOE. One thousand barrels of oil equivalent.

 

MMBtu. One million British Thermal Units.

 

MMcf. One million cubic feet of natural gas.

 

NGLs. Natural gas liquids, the combination of ethane, butane, isobutene and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

 

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be. For example, an owner who has 50% interest in 100 gross acres owns 50 net acres.

 

Net revenue interest or NRI. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

 

NYMEX. The New York Mercantile Exchange.

 

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

 

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

 

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

 

PDNP Reserves. Proved developed non-producing reserves. Hydrocarbons in a potentially producing horizon penetrated by a well bore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the well bore. The hydrocarbons are classified as proved, but non-producing reserves.

 

 

PDP. Proved developed producing.

 

PDP Reserves. Proved developed producing reserves. Reserves that are being recovered through existing wells with existing equipment and operating methods.

 

Proppant. A proppant is a solid material, typically sand, treated sand or man-made ceramic materials, designed to keep an induced hydraulic fracture open, during or following a fracturing treatment.

 

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

 

Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of “proved oil and natural gas reserves”, refer to the SEC’s Regulation S- X, Rule 4,- 10(a)(22).

 

PUD. Proved undeveloped reserve.

 

PUD Reserves. Proved undeveloped reserves, 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.

 

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

 

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

 

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

 

PV-10. Present value of future net revenues.

 

Reasonable certainty. A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S- X, Rule 4- 10(a)(24).

 

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

 

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.

 

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.

 

Royalty. An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

 

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40- acre spacing, and is often established by regulatory agencies.

 

 

Stacked pay. Multiple geological zones that potentially contain hydrocarbons and are arranged in a vertical stack.

 

Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

 

Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

 

TD. Total Depth.

 

Tight formation. A formation with low permeability that produces natural gas with very low flow rates for long periods of time.

 

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

 

WTI. West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, 39 and 41, and a sulphur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

 

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

 

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

 

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

 

 

PART I

 

ITEM 1 - BUSINESS

 

Overview

 

We are an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Delaware Basin portion of the Permian Basin in West Texas. The Delaware Basin, which is one of the major oil and gas producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a relatively large number of operators. 

 

Arabella Exploration, Inc., or Arabella, was organized on June 17, 2010 as an exempted company under the laws of the Cayman Islands. Arabella was a blank check company formed to acquire one or more operating businesses. On December 24, 2013, we consummated the acquisition of Arabella Exploration, LLC, or Arabella LLC, as more fully described below and, on February 4, 2013, we changed our name from Lone Oak Acquisition Corporation to Arabella Exploration, Inc. Our wholly-owned subsidiary, Arabella LLC, was established in the State of Texas on December 15, 2008 but did not conduct any material business operations until 2011 with the acquisition of properties in the Permian Basin.

 

In 2014 we formed Arabella Operating, LLC (“AOC”) to assume the role of operator of our wells from Arabella Petroleum Company, LLC (“APC”), the historic operator. On December 31, 2014 AOC was elected as the operator of record on our properties. Additionally in 2014 we formed Arabella Midstream, LLC which has not had any activity to date.

 

During 2015 the dramatic and continuing decline in oil and gas prices caused significant damage to our assets and business. Among other things, we were forced to write down the value of our oil and gas assets by $21,202,608 reflecting acreage and wells lost to lease expiration and the reduced production economics on our producing wells. Reduced oil pricing has also dramatically reduced our proven reserves through the reduction in the dollar value of our reserve barrels of oil and the number of barrels that we can produce economically over the expected life of ours wells. The adverse pricing conditions have lead to operating losses which were exacerbated by the non-cash earnings charge for the oil and gas asset impairment. Further, the reduced revenue resulting from the prices for oil and gas has left us unable to service and repay our Senior Secured Notes which came due on September 2, 2015.

 

Business of the Company

 

We began acquiring our core properties in the spring of 2011 with the acquisition of 1,600 gross acres in the Southern Delaware Basin. Between our initial purchase and December 31, 2014, we acquired approximately 9,282 additional gross acres, sold approximately 2,390 gross acres and backed into approximately 26,429 gross acres, which brought our total gross acreage position in the Delaware Basin to 34,921 gross acres, or 4,972 net acres, at December 31, 2014. At the time of these acquisitions, none of the acquired acreage had existing production. During 2015, we lost our SM Prewitt lease including the shut in SM Prewitt #1H well. We also lost portions of our Vastar State property as well as several undeveloped properties to lease expiration. Taking into account the foregoing, our net acreage position in the Delaware Basin was approximately 29,670 gross and 1,562 net acres as of December 31, 2015.

 

AEX Operating, LLC, a wholly owned subsidiary of Arabella, is the operator of record for our acreage. As of December 31, 2015, we had participated in eight gross, 2.96 net, wells, in the Delaware Basin. Of these eight gross wells, all were completed as producing wells.  The forgoing includes our Woods #2H well which is currently producing as the result of a data frac, but is awaiting full completion.

 

Our activities are primarily focused on the Wolfcamp and Bone Spring formations, which we refer to collectively as the Wolfbone play. The Wolfbone play is characterized by high oil content and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates.

 

As of December 31, 2015, our estimated net proved oil reserves were 785,470 MBbls and natural gas reserves were 1,571,842 MMcf, based on a reserve report prepared by W.D. Von Gonten & Co., or WDVG, independent reserve engineers. Of the proved oil reserves, approximately 19.2% are classified as proved developed producing, or PDP, and proved developed non-producing, or PDNP, the remaining 80.8% are classified as proved undeveloped, or PUD. Of the proved gas reserves, approximately 19.0% are classified as PDP and PDNP and the remaining 81.0% are classified as PUD. PUD reserves included in this estimate are from three gross horizontal well locations. As of December 31, 2015, these proved reserves were approximately 75.0% oil and 25.0% natural gas.

 

 

Additionally, we had 0 MBbls of probable and 0 MBbls of possible oil reserves, as well as 0 MMcf of probable and 0 MMcf of possible gas reserves.

 

In 2012, we began testing the horizontal well potential of our Delaware Basin acreage. Our first horizontal well was the SM Prewitt #1H in Reeves County with an approximate 4,200 foot lateral in the Wolfcamp C interval. It was completed in December 2012 and had a 24-hour initial production rate of 283 BOE/d and a 30-day average initial production rate of 146 BOE/d, of which 89.0% was oil. Through the end of December 31, 2015, the SM Prewitt #1H had produced a total of 13.5 MBbls of oil and 15.7 MMcf of natural gas. We began a dual lateral completion in our SM Prewitt #1H well by drilling a second lateral stage off of the original vertical well bore in the Wolfcamp A interval but did not complete that lateral. The SM Prewitt #1H was lost to lease expiration in 2015.

 

Our second horizontal well was the Locker State #1H, which was completed in March of 2013. It was completed in the Wolfcamp D interval with an approximately 4,200 foot lateral. The production was a peak 24 hour rate of 350 BOE/d and peak 30 day rate of 109 BOE/d, of which 85.0% was oil. Through the end of December 31, 2015, the Locker State #1H had produced a total of 24.1 MBbls of oil and 65.3 MMcf of natural gas. We own an 18.6% working interest in this well.

 

Our third horizontal well was the Graham #1H, which was completed in May 2013. It was completed in the Wolfcamp D interval with an approximately 4,200 foot lateral. The production was a peak 24 hour rate of 634 BOE/d and a peak 30 day rate of 383 BOE/d, of which 83.0% was oil. Through December 31, 2015, the Graham #1H had produced a total of 53.7 MBbls of oil and 146.5 MMcf of natural gas. We own a 19.6% working interest in this well.

 

Our fourth horizontal well was the Woods #1H, which was completed in August 2013. It was completed in the Wolfcamp B interval with an approximately 4,200 foot lateral. The production was a peak 24 hour rate of 1,221 BOE/d and a peak 30 day rate of 634 BOE/d, of which 87.0% was oil. Through December 31, 2015, the Woods #1H had produced a total of 82.8 MBbls of oil and 98.5 MMcf of natural gas. We own a 23.2% working interest in this well.

 

We drilled one vertical well, the Vastar State #1V, which was completed in December 2013. Through December 31, 2015, the Vastar State #1V had produced a total of 5.6 MBbls of oil and 8.0 MMcf of natural gas. We own a 62.1% working interest in this well.

 

Our fifth horizontal well was the Jackson #1H, which was completed in January of 2014. It was completed in the Wolfcamp B interval with an approximately 4,200 foot lateral. The production was a peak 24 hour rate of 875 BOE/d and a peak 30 day rate of 402 BOE/d, of which 82.0% was oil. Through December 31, 2015, the Jackson #1H had produced a total of 35.8 MBbls of oil and 55.0 MMcf of natural gas. We own a 60.2% working interest in this well.

 

Our sixth horizontal well was the Emily Bell #1H, which was completed in June 2014. It was completed in the Wolfcamp A interval with an approximately 4,200 foot lateral. The production was a peak 24 hour rate of 1,125 BOE/d and a peak 30 day rate of 482 BOE/d, of which 85.0% was oil. Through December 31, 2015, the Emily Bell #1H had produced a total of 39.5 MBbls of oil and 75.3 MMcf of natural gas. We own a 55.9% working interest in this well.

 

Our seventh horizontal well was the Woods #2H, which has been drilled and is awaiting completion. We performed a data frac on this well and through December 31, 2015 it had produced oil and gas while awaiting final completion. We own a 33.1% working interest in this well.

 

Well		Working Interest				Lateral Length (ft)				Completed Formation		Peak Rate 24-hour (BOE/d)				Peak Rate 30-day (BOE/d)				Percent Oil (%)
Locker State #1H			18.5500				4,200			Wolfcamp D			350				109				85
Graham #1H			19.5500				4,200			Wolfcamp D			634				383				83
Woods #1H			23.1562				4,200			Wolfcamp B			1,221				634				82
Vastar State #1V			62.1375				Vertical			Wolfcamp A-D			TBD				TBD				87
Jackson #1H			60.1647				4,200			Wolfcamp B			875				402				82
Emily Bell #1H			55.8750				4,200			Wolfcamp A			1,125				482				85
Woods #2H			33.1438				4,200			Wolfcamp B			TBD				TBD				95

 

 

All of our wells are currently operated by Arabella Operating, LLC, a wholly owned subsidiary of Arabella.

 

Through our back-in after payout options in the properties of certain other operators we have backed into interests ranging from 0.1 – 1.6% in twelve wells in the Southern Delaware Basin.

 

The production results from the wells in Reeves and Ward Counties, along with the basin wide geoscience and engineering data that Arabella has gathered and analyzed, give us confidence that our acreage in Reeves and Ward is prospective in the Wolfcamp A, B, C and D intervals. The data and offset well performance also indicate that all of our other Delaware Basin acreage is highly prospective for horizontal drilling and in multiple formations. The formations include not only the Wolfcamp A, B, C and D intervals, but other intervals in the Avalon and Bone Spring formations. However, further testing of these areas and other intervals is necessary to determine their economic potential.

 

The rapid and substantial decline in oil prices in the later part of 2014 and in 2015 significantly reduced the amount of revenue we receive per barrel of oil. Approximately 95% of our oil and gas revenue comes from oil sales. This decline has reduced our revenue and, as a result, our cash flow, which limits our operations and could limit our future growth. In addition, the decline in oil prices has made the drilling of certain wells uneconomic, and, until prices rebound significantly, we have been forced to curtail our drilling activities. We are currently not engaged in any drilling activity due to the reduced price of oil. Our current cash position is not adequate to support our current working capital requirements, interest costs and, at the same time, support additional drilling activity. The current oil pricing environment and related conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management is exploring various opportunities to remedy the Company’s liquidity concerns.

 

Strategy

 

Our business strategy is to increase stockholder value through the following:

 

●

Maximize the value of our properties and others that we may acquire. We intend to actively pursue and identify the maximum value obtainable from both our acreage and other acreage that we may acquire.

 

●

Grow production and reserves by developing our properties. Once oil prices improve, we will examine ways to develop our acreage base in an effort to maximize its value and resource potential in a manner that is consistent with the existing oil and gas pricing environment throughout the year. Through the conversion of its undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital.

 

●

Pursue strategic acquisitions with exceptional resource potential. We have a history of acquiring leasehold positions in the Southern Delaware Basin that have substantial oil-weighted resource potential and can achieve attractive returns on invested capital. Our executive team, with its extensive experience in the Southern Delaware Basin, which includes at one time having leased over 125,000 acres in the Southern Delaware Basin, has what we believes is a competitive advantage in identifying acquisition targets and an ability to evaluate resource potential. In the current oil and gas environment opportunities may exist to obtain assets at favorable values. We intend to examine acquisitions that may meet our strategic and financial targets.

 

●

Acquire additional development acreage through “farm in” opportunities. Because of our management team’s strong drilling and development track record and its deep knowledge of the Delaware Basin, we believe that we will be able to increase our acreage position at a better than market cost through “farm in” arrangement with other leaseholders in the Delaware Basin. There are a number of individuals and entities that have leased acreage in the Delaware Basin that do not have the technical or capital capacity to drill and develop their acreage. Our ability to drill complicated horizontal wells, manage multi-rig drilling programs, design and execute hydraulic fracture stimulation, and optimize production and capital efficiency enhances our position amongst our peers in the Delaware Basin. In many leasehold positions, if the current leaseholder does not drill a well on the acreage within the term of the lease (typically within the next two and one half years), the current leaseholder will be contractually compelled to surrender the lease. It is more advantageous to the current holder of the lease, assuming they do not have the ability for whatever reason to drill or develop the lease, to allow us to drill and develop a portion of their lease as the operator through a structured transaction wherein the current holder receives a carried interest in the lease instead of paying a large cash sum to renew the lease. Our research indicates in excess of 100,000 acres of potential “farm in” opportunities in our target area. In the current oil and gas environment opportunities may exist to obtain farm in opportunities on favorable terms. We intend to examine these opportunities that may meet our strategic and financial targets.

 

 

Our Strengths

 

We believe that the following competitive strengths will help us successfully execute our business goals:

 

●

Experienced management team. Our executive team has significant experience, acquiring, valuing and exploiting oil-producing land. Our executive team, with its extensive experience in the Southern Delaware Basin, which includes at one time having leased over 125,000 acres in the Southern Delaware Basin, has what we believes is a competitive advantage in identifying acquisition targets and an ability to evaluate resource potential.

 

●

High quality acreage in oil rich, leading resource play. All of our leasehold acreage is located in one of the most prolific oil plays in North America, the Southern Delaware Basin portion of the Permian Basin in West Texas. During the current downturn in oil and gas prices the Permian has shown the greatest resilience of the major Basins in the U.S. The majority of our current properties are located in some of the best portions in the core of the Wolfbone play, with no fringe acreage, and a focus on the oilier, overpressured portions of the Basin. Our production was approximately 83% oil and 17% natural gas for 2015.

 

●

Comparatively favorable and stable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With approximately 380,000 wells drilled in the Permian Basin since the 1940s, we believe that the geological and regulatory environment is more stable and predictable, and that we are faced with fewer operational risks in the Permian Basin as compared to emerging hydrocarbon basins. The Permian has weathered the current oil and gas pricing environment far better than most major basins in the U.S. as we feel our experience and presence in this basin will provide us opportunity when oil prices recover.

 

Review of Exploration, Exploitation and Development Activities

 

Area History

 

Location and Land – Delaware Basin Located in the Western half of the Permian Basin

 

The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. We acquired approximately 1,600 gross acres directly from mineral owners in West Texas (near Pecos, Texas) in the Delaware Basin portion of the Permian Basin in 2011 and subsequently acquired approximately 9,282 additional gross acres. Between our initial purchase and December 31, 2014, we acquired approximately 9,282 additional gross acres, sold approximately 2,390 gross acres and backed into approximately 26,429 gross acres, which brought our total gross acreage position in the Delaware Basin to 34,921 gross acres, or 4,972 net acres, at December 31, 2014. During 2015, we lost several properties to lease expiration. Our net acreage position in the Delaware Basin was approximately 29,670 gross and 1,562 net acres as of December 31, 2015. Since our initial acquisition, and through December 31, 2015, we have drilled eight gross horizontal wells (with one of these wells being a dual lateral horizontal well) on our leaseholds in this area, exclusively targeting the Wolfbone play of the Delaware Basin. We are the operator of the majority of our acreage.

 

 

Delaware Basin Development History

 

Our reserves are located in the Permian Basin of West Texas and focused on the Delaware Basin of West Texas and Southeast New Mexico. We believe Arabella has been instrumental in the development of the Wolfbone unconventional play. For example, we have leased more 125,000 acres in the play beginning in 2006 and Rich Masterson, our geologist, worked with a number of development companies in the early years of the play. The Wolfbone consists of Wolfcampian age rocks deposited in the deep Delaware trench, which continued to fill into Leonardian time in the Bone Spring Formations. The play was initiated when geologists identified that well samples and mudlog oil and gas shows were in rocks not known for reservoir characteristics, but were consistent and correlative over expansive portions of the Delaware Basin. The rock information was from older deeper gas wells drilled for Devonian, Silurian and Ordovician age structural entrapment. During drilling for these deeper target formations, wells would regularly encounter oil on the pits and high gas readings that indicated oil and gas saturation with high bottom hole pressures. These shows were present in the 4,000 feet of silty shales in the Basin fill above the deeper targeted formations. This shallower rock was considered at the time to be another non-productive localized lens and only occasionally would be completed with a small acid treatment to hold acreage over the conventional deeper gas plays. A few fields were found where very tight sandstones were deposited, encased in the silty shales. The Gomez Wolfcamp Field was discovered in 1976 and the wells produced at far higher productive rates than the sandstone reservoir had capacity and capability. The poor fracture stimulations during the 1970s still drained a portion of the surrounding siltstones. Shell Oil and Texaco, and later Tenneco, tried and successfully extended the Wolfcamp sand play. Most of the area was condemned as a reservoir because it was considered too tight and argillaceous but most geologists recognized the Wolfcamp as being the thickest source rock for the Basin.

 

In 2004, the Barnett Shale formation was being developed using large slick water fracture stimulation to extract gas from this extremely tight shale. Chesapeake, Petrohunt, EOG and others attempted to establish production from the Barnett in the Delaware Basin, where they encountered good gas shows. After several attempts, the Barnett in the Delaware Basin was found to be too tight to produce economically. However, these operators did bring the large frac jobs and horizontal drilling to West Texas. Zones like the 3^rd, or basal, Bone Spring initially was attempted in the War-Wink West Field northwest of Pyote, Texas. In 2005, Cimarex reentered conventionally produced thin silty sandstones and drilled out horizontally in small hole sizes and had some economic success, completing the horizontal with multi-stage frac jobs. This developed into an extensive expansion of the Upper 3^rd Bone Spring, but the understanding of the relationship between the 3^rd Bone Spring sand reservoir and the organic rich silts of the 2^nd Bone Spring and Wolfcamp was still very limited.

 

In late 2009, J Cleo Thompson and Eagle Oil & Gas began to test the Bone Spring in vertical wells in Reeves County and found it productive. Later that year J. Cleo Thompson tested only the Wolfcampian silts, tight limes, shales and sandstones in the Floyd 43 well eight miles southeast of Pecos, Texas. This well proved that the entire Upper Wolfcampian section of approximately 1,000 feet in thickness was productive for oil and gas, and that it was overpressured. Further, development and denser spacing of the vertical multi-stage frac designs improved the productivity of the wells. New frac designs with higher pump rates have also improved production. Petrophysical information from production tests, mudlogs, cores and new electric log combinations (CMR, Triple Combo, Sonic Scanner, Imaging tools and Lithoscanner) helped to evaluate and segregate the better rock from the poorer and identify true frac boundaries. Recipes for proper reservoir characteristics are now better understood. The better horizontal targets are selected for reservoir quality and capability of staying in the objective zones while drilling horizontally. Future study to understand the frac geometries will help determine vertical distances between the horizontals. At least 6 separate horizontal targets per 160 acre spacing have been identified in most of the central Delaware Basin and with at least four targets identified on the Basin fringes.

 

Geology

 

Intense plate tectonics created the deep trench of the Delaware Basin during late Mississippian through Pennsylvanian time. Left lateral faulting and resulting subsidence in the Delaware Basin filling during the late Pennsylvanian and Early Wolfcampian time set the stage for the deposition of the Wolfbone play.

 

The Delaware Basin has produced oil and gas from the Permian through Ellenberger age rocks. To the east is the abrupt facies change into the shelf edge carbonates in the Bone Spring and the 6,000 feet of abrupt structural relief and facies change of the Wolfcamp. To the west of Pecos, Texas is the northwest striking and gently eastern dipping monocline of the very asymmetrical Delaware Basin.

 

The Wolfcampian age portion of the Wolfbone was deposited predominately in a starved trench with little to no sunlight or oxygen. Having little tectonic or depositional influences during deposition preserved this reducing environment. Most of the basinal fill is windblown silts and fine silts caught in off shore currents. Whole core data has backed this interpretation. Pelagic algal and other organic skeletal debris form the makeup of the thin limes that are interbedded with the silts. Occasionally near the shelf edges, short periods of carbonate breccia and conglomerates occur locally. Often the breccias consist of deep water Crinoid fragments. The Basin filled like a bowl with a thick center, an abrupt eastern rim and a gently rising western flank. The geochemistry of the organic matter within the reducing environment and depth of burial created a thick succession of bitumen rich rock that reached a thermal maturity for oil. Interbedded with the silts are high clay rich shales and siliceous limestones that are impermeable and create seals that help concentrate pressure and high TOC intervals below the seals. The intervals are overpressured (pg. = 0.71 to 0.80). The seals are thin and are breached if near high-energy depositional facies or intense fracturing due to deeper-seated faulting. The better wells are in the down thrown fault blocks or grabens.

 

 

The siltstones that exhibit the best reservoir quality have low clay content, calcite cement for brittleness, high TOCs, and larger pore throat sizes. These qualities can be recognized in the Schlumberger logging suite.

 

Mudlog shows on the gas chromatograph combined with oil cuts and insoluble residues also corroborate the electric log suite. Sidewall coring and whole core analysis tied to the logging suites also better define cut offs for reservoir parameters. Multiple horizontal targets are selected from these studies. All the four horizontal targets attempted to date are successful oil and gas completions. Arabella is currently drilling in or producing from all four of the horizontal targets at depths of 10,000 to 10,700 feet.

 

The Bone Spring deposition is similar to the Wolfcampian although at a shallower (8,000 to 11,100 feet) depth. The Bone Spring is divided into three Geological Formations. The deepest and oldest is the 3^rd Bone Spring deposited above the Wolfcamp. It has been extensively horizontalled throughout the Delaware Basin with some production communication with the Upper Wolfcampian producing horizon. The top of the 3^rd Bone Spring has an ash fall structural marker that occurs in all the basinal wells. The 3^rd Bone Spring produces from a series of dolomite cemented silty sands and vertically adjoining silty shales. It is slightly overpressured (pg. = 0.68 to 0.72).

 

The 2^nd Bone Spring Siltstone overlies the Third Bone Spring marker. It is 300 feet thick and mostly overpressured (pg. = 0.70). It has been tested vertically and horizontally from New Mexico to Balmorhea, Texas. Some of the most productive tests in this zone lie near Arabella acreage located southeast of Pecos. Horizontal wells have initially produced at rates of over 1,200 BOE/day.

 

The 1^st Bone Spring produces from sandy siltstones and carbonate detrital interbedded with organic rich shales. It is being extensively developed from two intervals that are locally named the Upper and Lower Avalon. The upper pay is about 150 feet below the top of the 1^st Bone Spring Lime. The Lower Avalon is 500 feet below the top of the 1^st Bone Spring Lime and appears to date to be the better producer. A majority of the wells seem to be producing from a gas condensate reservoir. The two zones are present throughout the Delaware Basin. A good cement job is needed so that frac communication doesn’t occur with overlying Brushy Canyon sands, which can contain water. These zones have higher porosities and permeabilities than the lower Bone Spring zones and also have lower frac gradients.

 

Production Status

 

As of December 31, 2015, there was production from the Locker State #1H, Graham #1H, Woods #1H, Vastar State #1V, Jackson #1H, Emily Bell #1H and Woods #2H wells.  We currently have six producing wells; the sixth of which is waiting on final completion. The SM Prewitt #1H was lost during 2015 and the Vastar State #1V is currently shut in.

 

Facilities

 

Our land oil and gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units.

 

Future Activity

 

Any future drilling and completion activity will be highly dependent on the recovery of prices for crude oil. If oil prices do not rebound significantly in a short time, it is highly unlikely that we will drill wells during 2016. We are not currently engaged in any drilling activity due to the reduced price of oil.

 

 

Oil and Gas Data

 

Proved Reserves

 

SEC Rule-Making Activity

 

In December 2008, the Securities and Exchange Commission, or the SEC, released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required, unless contractual arrangements designate the price to be used. Other significant amendments included the following:

 

●

Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis.

 

●

Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. Please see Regulation S-X Rule 4-10(a)(22) (“Proved Oil and Gas Reserves”) and Rule 4-10(a)(31) (“Undeveloped Oil and Gas Reserves”) for further information on these guidelines.

 

●

Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

 

●

Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

 

●

Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

 

We adopted the rules effective December 31, 2009, as required by the SEC.

 

Evaluation and Review of Reserves

 

Our historical reserve estimates were prepared by Williamson Petroleum Consultants, Inc. (“WPC”) as of December 31, 2014 and W.D. Von Gonten & Co. (“WDVG”) as of December 31, 2015, in each case with respect to our assets in the Permian Basin. These reports cover 100% of our total reserves. The assumptions, data, methods and procedures employed by WDVG and WPC are appropriate for the purpose served by the reports and WDVG and WPC have used all methods and procedures as they considered necessary under the circumstances to prepare the reports.

 

WDVG is an independent petroleum engineering firm registered in the state of Texas. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. WDVG is an independent third-party engineering firm and owns no interest in any of our properties or is employed by us on a contingent basis.

 

William D. Von Gonten, Jr. is the President of WDVG and is the technical person primarily responsible for evaluating the proved reserves covered by this report. Mr. Von Gonten has almost 30 years’ experience in evaluating oil and gas reserves. Mr. Von Gonten holds a Bachelor of Science Degree from Texas A&M University. He is a Registered Professional Engineer in the States of Texas. He is a member of the Society of Petroleum Engineers, the Society of Petrophysicists and Well Log Analysts and the Houston Producers’ Forum.

 

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our 2014 and 2015 proved reserves were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 85% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 15% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

 

 

To estimate economically recoverable proved reserves and related future net cash flows, WDVG considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

 

We maintain a staff of geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.

 

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 

●

review and verification of historical production data, which data is based on actual production as reported by us;

 

●

preparation of reserve estimates by our management team or under their direct supervision;

 

●

direct reporting responsibilities by our management team to our Chief Executive Officer;

 

●

verification of property ownership by our land department; and

 

●

no employee’s compensation being tied to the amount of reserves booked.

 

 

The following table presents our estimated net proved oil and natural gas reserves and the present value of our reserves as of December 31, 2015 and 2014, based on the reserve reports prepared by WDVG and WPC. Such reserve reports have been prepared in accordance with the rules and regulations of the SEC. Although a specific lease may not have proved reserves, probable and possible reserves were assigned on the leases based on the interpretation of geologic and engineering data of the widespread productive area of the formations. Reserves assigned as probable or possible reflect the reduced certainty of the wells to be drilled. Probable and possible reserves assigned were estimated using SEC rules 4-10(a)(17) and (18) of Regulation S-X. All our proved reserves included in the reserve reports are located in North America.

 

		December 31 (1)
		2015				2014
Estimated proved developed reserves:
Oil (MBbls)			150.9				460.8
Natural gas (MMcf)			298.6				1,656.2
Natural gas liquids (MBbls)			-				-
Total (MBOE)			200.7				736.8
Estimated proved undeveloped reserves:
Oil (MBbls)			634.6				2,049.2
Natural gas (MMcf)			1,273.2				6,148.7
Natural gas liquids (MBbls)			-				-
Total (MBOE)			846.8				3,073.9
Estimated net proved reserves:
Oil (MBbls)			785.5				2,509.9
Natural gas (MMcf)			1,571.8				7,804.8
Natural gas liquids (MBbls)			-				-
Total (MBOE)			1,047.4				3,810.7
Percent proved developed			19.2	%			19.3	%
Probable developed reserves
Oil (MBbls)			-				-
Natural gas (MMcf)			-				-
Natural gas liquids (MBbls)			-				-
Total (MBOE)			-				-
Probable undeveloped reserves
Oil (MBbls)			-				-
Natural gas (MMcf)			-				-
Natural gas liquids (MBbls)			-				-
Total (MBOE)			-				-
Possible developed reserves
Oil (MBbls)			-				-
Natural gas (MMcf)			-				-
Natural gas liquids (MBbls)			-				-
Total (MBOE)			-				-
Possible undeveloped reserves
Oil (MBbls)			-				1,194.6
Natural gas (MMcf)			-				2,448.9
Natural gas liquids (MBbls)			-				-
Total (MBOE)			-				1,602.7

 

(1)

Estimates of reserves as of December 31, 2015 and December 31, 2014 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2015 and December 31, 2014, respectively, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

 

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers of production rates, recovery economics and PUD locations often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. We has not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC. 

 

 

Proved Undeveloped Reserves (PUDs) 

 

As of December 31, 2015, our proved undeveloped reserves totaled 634,586 MBbls of oil and 1,273,248 MMcf of natural gas for a total of 846,794 MBOE. As of December 31, 2014, our proved undeveloped reserves totaled 2,049,148 MBbls of oil and 6,148,660 MMcf of natural gas for a total of 3,073,925 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. 

 

Changes in PUDs that occurred during 2015 were primarily due to: 

 

●

additions of 0 MBOE attributable to extensions resulting from strategic drilling of wells to delineate our acreage position;

 

●

the conversion of approximately 0 MBOE from PUDs into proved developed reserves from drilling of wells;

 

●

the addition of approximately 0 MBOE from other changes including acquisition of working interests in our existing wells; and

 

●

the removal of 2,790,444 MBOE in PUDs through the changes in oil well drilling economics based on current oil prices as compared to the previous year.

 

No costs were incurred relating to the development of PUDs during 2015. Estimated future development costs relating to the development of PUDs, including existing PUDs and future PUDs developed from drilling or acquired, depending on the pace of drilling and the oil and gas pricing environment, are projected to be approximately $4.3 million in 2019 and $7.5 million in 2020. However, the forgoing is highly dependent on the price of oil and may be adjusted if prices remain depressed. When we continue to develop our properties and have more well production and completion data, we believe we will realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves. These anticipated lower drilling and completion costs are not incorporated into our proved reserve estimates as of December 31, 2015.

 

The following table shows how our total net proved reserves decreased from December 31, 2014 to December 31, 2015.

 

		Amount of increase (decrease)
Method of Increase (Decrease)		Oil (Bbls)				Natural Gas (Mcf)
Production			(25,408	)			(31,746	)
Purchase and discoveries of minerals in place			20,169				41,819
Impairment of oil and gas properties			(1,744,642	)			(6,274,812	)

 

All of our PUD drilling locations are scheduled to be drilled prior to the end of 2020. As of December 31, 2015, our Woods #2H well included in total proved reserves was classified as proved developed non-producing.

 

Oil and Gas Production Prices and Production Costs

 

Production and Price History

 

The following table sets forth information regarding our net production of oil, natural gas and natural gas liquids, all of which is from the Permian Basin in West Texas, and certain price and cost information for each of the periods indicated.

 

		December 31,
		2015				2014
Production Data:
Oil (Bbls)			25,408				37,191
Natural gas (Mcf)			31,746				36,258
Combined volumes (BOE)			30,699				43,234
Daily combined volumes (BOE/d)			84.1				118.5
Average Prices(1):
Oil (per Bbl)		$	39.03			$	85.97
Natural gas (per Mcf)			3.07				4.23
Combined (per BOE)			35.47				77.50
Average Costs (per BOE):
Lease operating expense		$	35.84			$	37.78
Production Taxes			2.38				3.54
Production Taxes as a % of sales			5.0	%			4.5	%
Depreciation, depletion and amortization			24,99				33.41
General and Administrative			93.70				116.32

 

 

Productive Wells

 

As of December 31, 2015, we owned an average 39% working interest in seven gross (2.72 net) productive wells. Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

 

Acreage

 

The following table sets forth information as of December 31, 2015 relating to our leasehold acreage:

 

Developed Acreage(1)

Undeveloped Acreage(2)

Total Acreage

Basin

Gross(3)

Net(4)

Gross(3)

Net(4)

Gross(3)

Net(4)

Permian

9,854

1,091

19,816

471

29,670

1,562

 

(1)	Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease.
(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
(3)	A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(4)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

 

Our current gross and net acreage figures are as follows for each of the following counties:

 

County		Gross Acreage				Net Acreage
Reeves County			14,660				1,080
Ward County			640				359
Pecos County			14,370				124

 

Undeveloped acreage expirations

 

Leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2015, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates. No PUD reserves were scheduled in our December 31, 2015 reserve report to be drilled after the lease expiration.

 

		2016								2017								2018								2019								2020
Permian Basin		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
December 31, 2015			10,096				136				4,961				262				1,844				114				-				-				-				-

 

 

Drilling Results

 

The following table sets forth information with respect to the number of wells completed during the periods indicated. Each of these wells was drilled in the Delaware Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

 

		December 31, 2015								December 31, 2014
		Gross				Net				Gross				Net
Development:
Productive			-				-				-				-
Dry			-				-				-				-
Exploratory:
Productive			8.0				3.0				8.0				3.0
Dry			-				-				-				-
Total:
Productive			8.0				3.0				8.0				3.0
Dry			-				-				-				-

 

Title to Properties

 

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our own expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

 

Marketing and Customers

 

We market our oil and natural gas production from properties we own. We sell our oil and natural gas to purchasers at market prices. Some of our natural gas contracts have terms of greater than twelve months and all of our oil contracts have terms of twelve months or less.

 

We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For 2015, two purchasers accounted for the majority of our revenue: Occidental Energy Marketing Inc. (33%), and Sunoco Partners (57%). In 2014, the same purchasers accounted for the majority of our revenue at 31% and 58%, respectively. If a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed in the applicable period. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

 

 

Competition

 

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than we do. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. 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 transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

 

Transportation

 

During the initial development of our fields, we consider all gathering and delivery infrastructure in the areas of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm where it is further transported by pipeline. Our natural gas is generally transported from the wellhead to the purchaser’s pipeline interconnection point through our gathering system.

 

Oil and Natural Gas Leases

 

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties are currently 25.00%, resulting in a net revenue to working interest owners of 75.00%.

 

Seasonal Nature of Business

 

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

 

Regulation

 

Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.

 

Environmental Matters and Regulation

 

Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

 

 

Waste Handling

 

The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of nonhazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

 

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we does not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

 

Remediation of Hazardous Substances

 

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), 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 the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

 

Water Discharges

 

The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for shale gas in 2016. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

 

 

The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

 

Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

 

Air Emissions

 

The Federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “ Regulation of Hydraulic Fracturing .” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

 

Climate Change

 

Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of GHGs. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate the emission of carbon dioxide from automobiles as an “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule, which purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016, in April 2010 and it became effective in January 2011, although it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation’s National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include 16 vehicles manufactured in model years 2017-2025. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although it remains subject of several pending lawsuits filed by industry groups. The Tailoring Rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the Tailoring Rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Tailoring Rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the Tailoring Rule, which went into effect in 2013, streamlines the permitting process and permanently exclude smaller sources from the permitting process. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities. The EPA is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries. The EPA has also adopted regulations imposing best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as “air pollutants.” As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

 

 

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

 

Regulation of Hydraulic Fracturing

 

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently 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. At the same time, the White House Council on Environmental Quality is coordinating an administration–wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2016 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

 

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing 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, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA.

 

 

On April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules required a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. In accordance with these rules our service companies have changed their products to comply with these regulations, and likewise the equipment we use is compliant.

 

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected in 2016. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

 

Several states, including Texas, and the Department of the Interior, in a May 4, 2012 proposed rule covering federal lands, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. On May 31, 2011, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. It was signed into law on June 17, 2011, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that will apply to all wells for which the Railroad Commission issues an initial drilling permit on or after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

 

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, 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 or state 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 or state legislation governing hydraulic fracturing.

 

Other Regulation of the Oil and Natural Gas Industry

 

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

 

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

 

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

 

Drilling and Production

 

Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate, also regulate one or more of the following:

 

●

the location of wells;

 

●

the method of drilling and casing wells;

 

●

the timing of construction or drilling activities, including seasonal wildlife closures;

 

●

the rates of production or “allowables”;

 

●

the surface use and restoration of properties upon which wells are drilled;

 

●

the plugging and abandoning of wells; and

 

●

notice to, and consultation with, surface owners and other third parties.

 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. 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 requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. 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. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

 

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

 

 

Natural Gas Sales and Transportation

 

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

 

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

 

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations

 

Oil Sales and Transportation

 

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

 

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, Arabella believes that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

 

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by portioning provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

 

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 you 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.

 

Operational Hazards and Insurance

 

The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

 

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies for onshore property (oil lease property/production equipment) for selected locations, rig physical damage protection, control of well protection for selected wells, comprehensive general liability, commercial automobile, workers compensation, pollution liability (claims made coverage with a policy retroactive date), excess umbrella liability and other coverage.

 

Our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

 

We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

 

Generally, we also require our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

 

Employees

 

As of December 31, 2015, we had five full time employees. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full time employees.

 

Facilities

 

Our corporate headquarters is located at 509 Pecan Street, Suite 200, Fort Worth, Texas, 76102. This facility is leased at $12,500 per month on a yearly basis. Our main telephone number is (432) 897-4755. We also may lease new office space in Midland, Texas but have not yet done so. We believe that our facilities are adequate for our current operations.

 

In 2014 we had an expense sharing agreement with APC concerning rent and certain other office expenses.

 

Available Information

 

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports, as well as other documents we file with the SEC, are available free of charge through the Investor Relations section of our web site (www.arabellaexploration.com) as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. The public can obtain documents that we file with the SEC at www.sec.gov.

 

 

ITEM 1A. RISK FACTORS

 

You should carefully consider these factors that may affect future results, together with all of the other information included in this Form 10-K, in evaluating the business and the Company. The risks and uncertainties described below are those that the Company currently believes may materially affect its business and results of operations.  Additional risks and uncertainties that the Company is unaware of or that it currently deems immaterial also may become important factors that affect its business and result of operations.  The Company's common shares involve a high degree of risk and should be purchased only by investors who can afford a loss of their entire investment.  Prospective investors should carefully consider the following risk factors concerning the Company's business before making an investment.

 

In addition, you should carefully consider these risks when you read “forward-looking” statements elsewhere in this Report. These are statements that relate to the Company's expectations for future events and time periods. Generally, the words “anticipate”, "expect", “intend", and similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, and future events and circumstances could differ significantly from those anticipated in the forward-looking statements. 

 

The reduction in oil prices since mid-2014 has significantly reduced our revenue and cash flow, and may continue to cause us to limit our drilling program.

 

The rapid and substantial decline in oil prices in the later part of 2014 and 2015 significantly reduced the amount of revenue we receive per barrel of oil. Approximately 95% of our oil and gas revenue comes from oil sales. This decline has reduced our revenue and, as a result, our cash flow, which limits our operations and could limit our future growth. In addition, the decline in oil prices may make the drilling of certain wells uneconomic, and, unless prices rebound significantly, we may be forced to limit our drilling activities.

 

As a result of lower prices for oil and gas we wrote down the value of our wells; a number of our leases expired

 

The rapid and substantial decline in oil prices in the later part of 2014 and 2015 significantly reduced the economic viability of our wells and the projected future cash flows therefrom. In addition, a number of our leases expired in 2015 and were not re-leased due to depressed oil prices. As a result, we incurred a $21,202,608 impairment charge against our earnings for the year ended December 31, 2015.

 

We have been unable to repay the our Senior Note facility which matured on September 2, 2015

 

Our Senior Note facility came due on September 2, 2015. We have been unable to repay the principal amount or interest on the notes.

 

Our Senior Lender Notified us that they were declaring our Senior Note facility in default.

 

On January 21, 2016 our Senior Lender notified us that they were declaring our Senior Note facility in default. The Senior Note Agreement provides the Senior Lender a number of possible remedies including, but not limited to, a default interest rate of 20%, the seizure of our revenues by the Senior Lender and the foreclosure on the collateral of the Senior Notes. Should our Senior Lender attempt to take any of these steps it would have a negative impact on our business.

 

We may not be able to continue as a going concern in the current oil pricing environment. If managements’ plans to re-orient the business fail we may be forced to cease operations.

 

The current oil pricing environment and related conditions raise substantial doubt about the Company’s ability to continue as a going concern. The report of our independent registered public accounting firm relating to our financial statements for the year ended December 31, 2015 includes an explanatory paragraph stating that these factors, among others, raise substantial doubt about our ability to continue as a going concern. The Company’s ability to continue as a going concern is dependent on its ability to generate revenue from oil and gas operations or asset sales and achieve profitable operations and/or to generate sufficient cash flow from debt or equity financing and operations to meet its obligations, as they become payable.

 

 

We have been named as a defendant in an action brought by the Trustee for the Arabella Petroleum bankruptcy that seeks to, among other things, to possibly have some of our properties returned to Arabella Petroleum.

 

We have been named as a defendant in an action brought by Morris Weiss, Chapter 11 Trustee for Arabella Petroleum, LLC (“APC”), a predecessor in interest to much of the acreage that AEX’s wholly owned subsidiary, Arabella, LLC, owns and which another wholly owned subsidiary, Arabella Operating, LLC, operates. The action alleges, among other things that the transfer of the majority of acreage owned by Arabella, LLC was constructively or actually fraudulent on the creditors of APC, are preferential transfers and that APC has, and should be allowed to foreclose on, a lien against those property interests. The APC Trustee seeks return of the properties to APC or the payment of the fair market value of those assets at the time of the transfer. The Trustee has not stated an amount of damages dollars.

 

A substantial or extended decline in oil and natural gas prices has adversely affected our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments. 

 

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets may be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following: 

 

	●	changes in global supply and demand for oil and natural gas;
	●	the actions of the Organization of Petroleum Exporting Countries, or OPEC;
	●	the price and quantity of imports of foreign oil and natural gas;
	●	political conditions, including embargoes, in or affecting other oil-producing activity;
	●	the level of global oil and natural gas exploration and production activity;
	●	the level of global oil and natural gas inventories;
	●	weather conditions;
	●	technological advances affecting energy consumption; and
	●	the price and availability of alternative fuels.

  

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices will also negatively impact the value of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

 

A substantial percentage of our proven properties are undeveloped; therefore the risk associated with our success is greater than would be the case if the majority of our properties were categorized as proved developed producing.

 

Because a substantial percentage of our proven properties are proved undeveloped (approximately 80.8%) we will require significant additional capital to develop such properties before they may become productive. Please see the section entitled “Oil and Gas Production Prices and Production Costs” below. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be developed and to create positive cash flow. 

 

In order to fund our development costs, we may be forced to seek alternative sources for cash, through the issuance of additional equity or debt securities, increased borrowings or other means. 

 

 

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

 

Approximately 80.8% of our total estimated proved reserves are proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

 

Our exploration and development operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

 

The oil and natural gas industry is capital intensive. In the event that we resume drilling or acquisition activities, we would need to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2016 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 traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, 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.

 

Our acreage must be drilled before lease expiration in order to hold the acreage by production. Failure to drill sufficient wells to hold acreage has and may continue to result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

 

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. We lost a number of our leases during 2015. For the remainder of our leases, the cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, has and could further result in the loss of acreage through lease expirations. Any such losses of leases has and could further materially and adversely affect the growth of our asset basis, cash flows and results of operations.

 

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. 

 

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate” (below) for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following: 

 

	●	delays imposed by or resulting from compliance with regulatory requirements;
	●	pressure or irregularities in geological formations;
	●	shortages of or delays in obtaining equipment and qualified personnel;
	●	equipment failures or accidents;
	●	adverse weather conditions;
	●	reductions in oil and natural gas prices;
	●	title problems; and
	●	limitations in the market for oil and natural gas.

 

 

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.

 

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

 

If our assessments of our properties are materially inaccurate, it could have significant impact on future operations and earnings. 

 

We have aggressively expanded our base of producing properties and, when conditions improve, could potentially continue to do so through development and acquisition. The successful acquisition or development of properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following: 

 

	●	the amount of recoverable reserves;
	●	future oil and natural gas prices;
	●	estimates of operating costs;
	●	estimates of future development costs;
	●	estimates of the costs and timing of plugging and abandonment; and
	●	potential environmental and other liabilities.

 

Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. As noted previously, we plan to undertake further development of our properties through the use of cash flow from existing production. Therefore, a material deviation in our assessments of these factors could result in less cash flow being available for such purposes than we presently anticipate, which could either delay future development operations (and delay the anticipated conversion of reserves into cash), or cause us to seek alternative sources to finance development activities. 

 

Our identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

 

Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

 

 

Decreases in oil and natural gas prices may reduce the amount of oil and gas we can produce economically. 

 

The production of oil and gas requires substantial upfront investment as well as ongoing costs. As such lower oil and natural gas prices reduce the amount of oil and natural gas that we can develop and produce economically. A determination that we were no longer able to economically explore for and develop new production has had a detrimental effect on our future growth. A determination that we were no longer able to economically produce oil and gas as a result of price declines would have significant impact on our financial results, ability to service our indebtedness and meet our other financial obligations.

 

Decreases in oil and natural gas prices required us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities. 

 

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we were required to write down the carrying value of our oil and natural gas properties. The write-down also constituted a non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our securities. 

 

We sell our natural gas to a limited number of buyers, and if one of our buyers was unable to pay us for our natural gas products, our financial results could be adversely affected. 

 

We sell the majority of our natural gas to a small number of natural gas purchasing companies. There is often consolidation in this market and it is possible that we might be faced with a significant concentration of our natural gas buyers. In the event that one of our natural gas buyers was unable to make payment to us for its purchases of natural gas, our financial results could be adversely affected. We sell our oil to many different buyers and believe that we have many primary and secondary buyers to choose from.

 

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. 

 

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reported reserves.  

 

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves may be inherently imprecise. 

 

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. 

 

You should not assume that the present value of future net revenues from our reported proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the average price during the 12-month period prior to the ending date of the period covered by the report. Actual future prices and costs may differ materially from those used in the present value estimate. If future values decline or costs increase it could negatively impact our ability to finance operations, and individual properties could cease being commercially viable, affecting our decision to continue operations on producing properties or to attempt to develop properties. All of these factors would have a negative impact on earnings and net income, and most likely the trading price of our securities. These factors could also result in the acceleration of debt repayment and a reduction in our borrowing base under any prospective credit facilities. 

  

 

We have limited experience drilling and operating wells and this experience may lead to variances, positive or negative, in our operations. 

 

We have a limited history of operating wells. This lack of experience could result in errors in the methods we use for drilling and maintaining our wells, which could result in poorer than expected operating results. In addition, the lack of experience operating wells could result in inefficiencies in its operations that result in greater expenditures than are required under the circumstances.

 

The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil reserves.

 

The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

 

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

 

Part of our strategy when we are developing our properties involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, we are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

 

In the event that we were to resume drilling, our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.

 

We may not be able to keep pace with technological developments in our 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 may be forced by competitive pressures 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 that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

 

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

 

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

 

 

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

 

Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled, to prospects that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the fact that a significant percentage (80.8%) of our proved reserves is currently proved undeveloped reserves. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

 

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

 

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system. Our purchasers then transport the oil by truck to a pipeline for transportation. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations.

 

We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

 

Our operations and drilling activity are concentrated in the Southern Delaware Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes.  Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.

 

We rely on a few key employees whose absence or loss could adversely affect our business.

 

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Jason Hoisager, could disrupt our operations. We have an employment agreement with Mr. Hoisager which, as a practical matter, may not assure his retention.

 

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

 

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

 

	●	environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
	●	abnormally pressured formations;

 

 

	●	mechanical difficulties such as stuck oil field drilling and service tools and casing collapse;
	●	fires and explosions;
	●	personal injuries and death; and
	●	natural disasters.

 

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, then it could adversely affect us.

 

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

 

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include: 

 

	●	discharge permits for drilling operations;
	●	drilling bonds;
	●	reports concerning operations;
	●	the spacing of wells;
	●	unitization and pooling of properties; and
	●	taxation.

 

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations. 

 

Our operations may incur substantial liabilities to comply with the environmental laws and regulations. 

 

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

 

 

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

 

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.   

 

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. 

 

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. 

 

Currently, the majority of our production is sold to marketers and other purchasers that have access to nearby pipeline facilities. However, as Arabella begins to further develop our properties, we may find production in areas with limited or no access to pipelines or compression facilities. Such restrictions on our ability to sell our oil or natural gas have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

 

Hedging transactions may limit our potential gains. 

 

In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements. 

 

All of our properties are located in the same major geographic area. 

 

Because substantially all of the properties leased by us are located in the Delaware Basin in Texas, we face geographic concentration risk. If the properties leased by us prove to be unable to produce profitable oil and natural gas, it may force us to seek properties in other regions. This could require us to make significant expenditures or cease operations, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition.

 

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

 

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

 

 

Our business is difficult to evaluate because we have a limited operating history.

 

Arabella Exploration, Inc., or Arabella, organized on June 17, 2010 as an exempted company under the laws of the Cayman Islands. Arabella was a blank check company formed to acquire one or more operating businesses. On December 24, 2013, we consummated the merger with Arabella Exploration, LLC and, on February 4, 2013, we changed our name from Lone Oak Acquisition Corporation to Arabella Exploration, Inc. Our wholly-owned subsidiary, Arabella LLC, was established in the State of Texas on December 15, 2008 but did not conduct any material business operations until 2011 with the acquisition of properties in the Permian Basin. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

  

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

 

As a recently-formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

 

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

 

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. 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 transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

 

Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.

 

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness, including the Senior Notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business has not generated cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. As a result, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.

 

 

If our indebtedness increases, it could reduce our financial flexibility. 

 

As of December 31, 2015, we had $16 million drawn on our Senior Secured Note facility in addition to accrued interest (see section entitled “Senior Secured Note Facility”). If in the future we raise funds through another debt facility, the level of our indebtedness could affect our operations in several ways, including the following:

 

	●	a significant portion of our cash flow could be used to service the indebtedness,
	●	a high level of debt would increase our vulnerability to general adverse economic and industry conditions,
	●	the covenants contained in a prospective credit facility may limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments,
	●	a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

 

Increased costs of capital could adversely affect our business.

 

Our business and operating results could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

 

Our largest stockholders control significant percentages of our common stock, and their interests may conflict with those of our other stockholders.

 

Some of our largest stockholders control large portions of our outstanding shares and as such are able to exercise significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it difficult for any other holder or group of holders of our ordinary shares to be able to affect the way we are managed or the direction of our business. The interests of these shareholders with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. This continued concentrated ownership might make it difficult for another company to acquire us and for you to receive any related takeover premium for your shares unless the large shareholders approve the acquisition.

 

The original shareholders of Lone Oak Acquisition Corporation maintain certain voting and contractual rights in addition to their rights as shareholders.

 

As a result of the Voting Rights and Merger Agreements from the merger, the Lone Oak shareholders maintain certain additional rights above their rights as shareholders including the right to appoint three directors, approve changes in certain management roles among other things. The interests of these shareholders with respect to matters potentially or actually involving or affecting us may conflict with the interests of our other stockholders.

 

We incur increased costs as a result of being a public company, which may significantly affect our financial condition.

 

We completed our reverse merger in December 2013. As a public company, we incur significant legal, accounting and other expenses that we did not incur as a private company. We also incur costs associated with our public company reporting requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. These rules and regulations increase our legal and financial compliance costs and make some activities more time-consuming and costly. These rules and regulations make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.

 

Our stock is thinly traded and the price fluctuates significantly, your investment could lose value.

 

Although our ordinary shares are listed on the OTC Bulletin Board, we cannot assure you that an active public market will continue for our ordinary shares. If an active public market for our ordinary shares does not continue, the trading price and liquidity of our ordinary shares will be materially and adversely affected. There is a thin trading market or “float” for our shares and the market price for our ordinary shares may fluctuate significantly more than the stock market as a whole. Without a large float, our ordinary shares would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our ordinary shares may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our ordinary shares could fluctuate widely in response to several factors.

 

 

Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.

 

Sales of substantial amounts of our ordinary shares in the public market, or the perception that these sales may occur, could cause the market price of our ordinary shares to decline. In addition, the sale of such shares, or the perception that such sales may occur, could impair our ability to raise capital through the sale of additional ordinary or preferred shares. Additionally we have several larger holders of our ordinary shares, in the event that one or more of our stockholders sells a substantial amount of our ordinary shares in the public market, or the market perceives that such sales may occur, the price of our stock could decline.

 

We do not intend to pay cash dividends on our ordinary shares in the foreseeable future and, therefore, only appreciation of the price of our ordinary shares will provide a return to our stockholders.

 

We have not paid dividends since our inception and we currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our board of directors. As a result, only appreciation of the price of our ordinary shares, which may not occur, will provide a return to our stockholders.

 

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

 

Our articles of incorporation authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our ordinary shares respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our ordinary shares. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the ordinary shares.

 

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

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

 

ITEM 2. PROPERTIES

 

For information concerning our properties, see Item I, “Business”.

 

ITEM 3. LEGAL PROCEEDINGS

 

We have been named as a defendant in an action brought by Morris Weiss, Chapter 11 Trustee for Arabella Petroleum, LLC (“APC”), a predecessor in interest to much of the acreage that our wholly owned subsidiary, Arabella, LLC, owns and which another wholly owned subsidiary, Arabella Operating, LLC, operates. Both subsidiaries are also named defendants, as is Platinum Long Term Growth VIII, LLC (“Platinum”), our senior secured lender. Platinum’s parent fund, one of our directors, Jason Hoisager, and a company owned by one Mr. Hoisager are also named defendants. The action alleges, among other things against parties other than us or our wholly owned subsidiaries, that the transfer of the majority of acreage owned by Arabella, LLC was constructively or actually fraudulent on the creditors of APC, are preferential transfers and that APC has, and should be allowed to foreclose on, a lien against those property interests. The APC Trustee seeks return of the properties to APC or the payment of the fair market value of those assets at the time of the transfer. The Trustee has not stated an amount of damages dollars. The answer date to the action has been set at April 29, 2016. We intend to vigorously defend ourselves and dispute both the factual and legal basis underpinning the suit. This action was only recently filed on February 29, 2016; little to no discovery has been undertaken and no substantive rulings have been made.

 

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us, unless previously mentioned in this section, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

 

ITEM 4.  MINE SAFETY DISCLOSURES

 

Not Applicable.

 

 

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

 

Our shares, warrants and units are quoted on the OTC Bulletin Board under the symbols AXPLF, AXLWF and AXPUF, respectively. The units have been quoted on the Bulletin Board since March 21, 2011. Our ordinary shares and warrants commenced to trade separately from our units on June 15, 2011.

 

The following tables set forth, for the periods indicated, the high and low sale prices for our units, ordinary shares and warrants, respectively, as reported on the Over-the-Counter Bulletin Board.

 

		Units								Ordinary Shares								Warrants
		High				Low				High				Low				High				Low
2014:
First Quarter			8.25				8.25				8.28				6.01				1.30				0.60
Second Quarter			8.25				8.25				9.00				4.50				2.46				0.75
Third Quarter			8.25				8.25				9.00				5.62				2.41				1.55
Fourth Quarter			8.25				8.25				6.49				2.50				1.60				0.42
2015:
First Quarter			8.25				8.25				3.35				2.55				0.54				0.30
Second Quarter			8.25				8.25				5.25				2.50				0.33				0.08
Third Quarter			8.25				8.25				2.50				0.55				0.30				0.02
Fourth Quarter			8.25				8.25				0.90				0.15				0.02				0.01

 

At April 13, 2015, the market price of the Company's ordinary shares was $0.35 per share.

 

As of December 31, 2015, there were 5,020,303 issued and outstanding shares of common stock. We are informed and believe these shares are held by 18 shareholders of record.

 

Dividend Policy

 

The Company does not plan to pay cash dividends at this time. The Company's Board of Directors (“Board”) will decide any future payment of dividends, depending on the Company's results of operations, financial condition, capital requirements and other relevant factors.

 

Issuer Purchases of Equity Securities

 

The Company did not repurchase any of its securities registered under Section 12 of the Exchange Act during the year ended December 31, 2015.

 

Securities Authorized for Issuance under Equity Compensation Plans.

 

For information concerning shares available for issuance under equity compensation plans, see Part III, “Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters”.

   

 

Recent Issuance of Unregistered Securities

 

On June 26, 2014 our Chief Executive Officer Jason Hoisager purchased 190,477 of the Company’s ordinary shares for $10.50 a share in a private subscription pursuant to the exemption from registration contained in Section 4(2) of the Securities Act as a transaction by an issuer not involving a public offering. The shares were new issue shares of the company.

 

 On May 5, 2014 we granted each non-employee director 30,000 stock options to purchase our ordinary shares for joining the board and 20,000 stock options to purchase our ordinary shares for each year of service commencing from January 30, 2014. The stock options vest ratably over two years and expire five years from the grant date. The stock options have an exercise price of $6.15 per share, which represents the closing price of our ordinary shares the day prior to the grant.

 

On September 2, 2014, in conjunction with the sale of notes under our Senior Secured Note Facility, we issued warrants to purchase 1,300,000 of our ordinary shares at a price of $5.00 pursuant to the exemption from registration contained in Section 4(2) of the Securities Act as a transaction by an issuer not involving a public offering. The warrants expire on September 2, 2019.

 

On February 2, 2015 we granted each non-employee director 20,000 stock options to purchase our ordinary shares for the year of service commencing from January 30, 2014 and concluding on January 30, 2015. The stock options vest ratably over two years and expire five years from the grant date. The stock options have an exercise price of $3.35 per share, which represents the closing price of our ordinary shares the day prior to the grant.

 

ITEM 6. SELECTED FINANCIAL DATA

 

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

 

 

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The following discussion may contain forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed here. Factors that could cause or contribute to such differences include, but are not limited to, any factors discussed in this section as well as factors described in “Part II, Item 1A – Risk Factors.”

 

Overview

 

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, long-life, onshore oil and natural gas reserves in the Delaware Basin in West Texas, which is a part of the Permian Basin. Our activities have historically been directed at the Avalon, Bone Springs, and Wolfcamp formations, which we refer to collectively as the Wolfbone play. 

 

Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production, though we do on occasion sell parcels of our land when the opportunity to generate profit presents itself. Our production was approximately 83% oil, no natural gas liquids and 17% natural gas for the year ended December 31, 2015, approximately 86% oil, no natural gas liquids and 14% natural gas for the year ended December 31, 2014. On December 31, 2015, our net acreage position in the Delaware Basin was approximately 1,562 net acres. On December 31, 2014, our net acreage position in the Delaware Basin was approximately 4,972 net acres. We are not currently engaged in any drilling activity due to the reduced price of oil.

 

We were organized on June 17, 2010 as an exempted company under the laws of the Cayman Islands. We were a blank check company formed to acquire through a merger, capital stock exchange, asset acquisition, stock purchase or similar business combination, or control through contractual arrangements, one or more operating businesses. On October 23, 2013, we entered into an Agreement and Plan of Merger and Reorganization to acquire Arabella, LLC, a Texas limited liability company (the “Acquisition”). On December 24, 2013, we consummated the Acquisition with Arabella LLC, as more fully described in our Annual Report on Form 20-F for the year ended December 31, 2013 filed on May 15, 2014. On February 4, 2013, we changed our name from Lone Oak Acquisition Corporation to Arabella Exploration, Inc. 

 

During 2015 the dramatic and continuing decline in oil and gas prices caused significant damage to our assets and business. Among other things, we were forced to write down the value of our oil and gas assets by $21,202,608 reflecting acreage and wells lost to lease expiration and the reduced production economics on our producing wells. Reduced oil pricing has also dramatically reduced our proven reserves through the reduction in the dollar value of our reserve barrels of oil and the number of barrels that we can produce economically over the expected life of ours wells. The adverse pricing conditions have lead to operating losses which were exacerbated by the non-cash earnings charge for the oil and gas asset impairment. Further, the reduced revenue resulting from the prices for oil and gas has left us unable to service and repay our Senior Secured Notes which came due on September 2, 2015.

 

Future Activity

 

Any future drilling and completion activity will be highly dependent on the recovery of prices for crude oil. If oil prices do not rebound significantly in a short time, it is highly unlikely that we will drill new wells. We are not currently engaged in any drilling activity due to the reduced price of oil.

 

Operating Results Overview 

 

During the year ended December 31, 2015, our average daily production was approximately 84 BOE, consisting of 70 Bbls/d of oil, 87 Mcf/d of natural gas and no natural gas liquids, this is a decrease from the year ending December 31, 2014, when our average daily production was approximately 118 BOE, consisting of 102 Bbls/d of oil, 99 Mcf/d of natural gas and no natural gas liquids. 

 

Through the year ended December 31, 2015, we had participated in 8 gross (2.96 net) operated wells in the Delaware Basin.

 

 

Reserves and pricing 

 

In the table below, WDVG estimated all of our proved reserves at December 31, 2015 and WPC at December 31, 2014. The prices used to estimate proved reserves for all periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. 

 

Estimated Net Proved Reserves:		December 31, 2015				December 31, 2014
Oil (MBbls)			785.5				2,509.9
Natural gas (MMcf)			1,571.8				7,804.8
Total (MBOE)			1,047.4				3,810.7

 

		December 31, 2015				December 31, 2014
		Unweighted Arithmetic Average First-Day-of-the-Month Prices
Oil (Bbls)		$	50.16			$	85.54
Natural gas (Mcf)			2.64				5.51

 

Sources of our revenue 

 

Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. For the years ended December 31, 2015 and December 31, 2014 our revenues were derived 91% and 94%, respectively, from oil sales, 0% and 0%, respectively, from natural gas liquids sales and 9% and 6%, respectively, from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2015, West Texas Intermediate posted prices ranged from $34.55 to $61.36 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.63 to $3.32 per MMBtu. On December 31, 2015, the West Texas Intermediate posted price for crude oil was $37.13 per Bbl and the Henry Hub spot market price of natural gas was $2.28 per MMBtu.

 

During the year ended December 31, 2014, we had other revenue from the gain on sale of oil and gas properties.

 

Principal components of our cost structure 

 

Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.  

 

Ad valorem and production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Arabella is also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties. 

 

Depreciation, depletion and amortization. We follow the successful efforts method for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized on a field by field basis using the unit-of-production method based on estimated proved reserves. Additionally, gain or loss is generally recognized on all sales of natural gas and oil properties under the successful efforts method.

 

Exploration expense. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties. 

 

 

General and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.  In 2014 we had an expense sharing agreement with APC concerning rent and certain other office expenses.

 

		Year Ended
		December 31, 2015				December 31, 2014
Revenues:
Oil and gas revenue		$	1,475,856			$	3,408,296
Other revenue – administrative overhead			39,600				-
Other operating revenue – gain on sale of oil and gas properties			-				3,084,917
Total revenues			1,515,456				6,493,213
Costs and expenses:
Lease operating expenses			1,100,312				1,633,456
Ad valorem and production taxes			73,182				153,231
Depreciation, depletion and amortization			767,116				1,444,315
(Reduction) accretion of asset retirement obligation			(1,353	)			1,770
General and administrative expenses			2,876,348				5,154,056
Impairment of oil and gas properties			21,202,608				--
Total costs and expenses			26,018,213				8,386,827
Loss from operations			(24,502,757	)			(1,893,614	)
Other expense
Interest expense, related party							(40,722	)
Interest expense			(7,153,516	)			(2,882,212	)
Total other expense			(7,153,516	)			(2,922,934	)
Net loss before taxes			(31,656,273	)			(4,816,548	)
Provision for income taxes			--				--
Net loss		$	(31,656,273	)		$	(4,816,548	)

 

		December 31,				December 31,
		2015				2014
Production Data:
Oil (Bbls)			25,408				37,191
Natural gas (Mcf)			31,746				36,258
Combined volumes (BOE)			30,699				43,234
Daily combined volumes (BOE/d)			84.1				118.5
Average Prices(1):
Oil (per Bbl)		$	39.03			$	85.97
Natural gas (per Mcf)			3.07				4.23
Combined (per BOE)			35.47				77.50
Average Costs (per BOE):
Lease operating expense		$	35.84			$	37.78
Production Taxes			2.38				3.54
Production Taxes as a % of sales			5.0	%			4.5	%
Depreciation, depletion and amortization			24.99				33.41
General and Administrative			93.70				116.32

 

 

Comparison of Years ended December 31, 2015 and December 31, 2014 

 

Oil and Natural Gas Revenues. Our oil and natural gas revenues decreased by $1,932,440, or 57%, to $1,475,856 for the year ended December 31, 2015, as compared to $3,408,296 for the year ended December 31, 2014. Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. The major reason for the decrease in revenues is due to the dramatic decline in oil and gas prices from the prior year as well as decreased production.

 

Other Revenue. Other revenue relates to administrative overhead fees paid to Arabella Operating by other working interest owners to operate our wells. Arabella Operating was paid $39,600 for the year ended December 31, 2015 and did not operate our wells for the year ended December 31, 2014.

 

Other Operating Revenue. Other operating revenue in 2014 relates to oil and gas property sales. In 2014, we sold properties for $5,665,121 with a net profit of $3,084,917. We did not have any property sales in 2015. Other operating revenue from the sale of oil and gas properties fluctuates due to market demand and preparation of the land. We buy and sell parcels of land when the opportunity to generate significant profit presents itself. 

 

Lease Operating Expense. Lease operating expenses decreased from $1,633,456 in 2015 to $1,100,3120 in 2014. This decrease is the direct result of reduced activity on our wells in response to the dramatic decline in oil and gas prices from the prior year. Lease operating expenses can vary based upon conditions at the well site and well productivity. We experienced significant difficulties in operating our wells during 2014 that increased our costs including power issues for our artificial lift systems and other logistical challenges. We also incurred over $500,000 of non-recurring professional costs associated with our operations in 2014 in the form of billings from the operator of our wells for legal, accounting and other items incurred by the operator. 

 

Ad Valorem and Production Tax Expense. Ad valorem and production taxes as a percentage of oil and natural gas revenues increased for 2015 as compared to 2014. There was an overall reduction in taxes due to the revenue decrease discussed above. Ad valorem and production taxes are primarily based on the market value of our production at the wellhead and may vary across the different counties in which we operate. 

 

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased from $1,444,315 in 2014 to $767,116 in 2015. The decrease is related to reduced production due to the decline in oil and gas prices. 

 

General and Administrative. General and administrative expenses decreased from $5,154,056 in 2014 to $2,876,348 in 2015. These expenses relate primarily to salaries and wages, legal fees and professional fees.  The decrease is related to reduction general and administrative costs related to reduced activity and cost cutting measures taken in response to the dramatically lower prices for oil in gas as opposed to the prior year.

 

Impairment of Oil and Gas Assets. Impairment of oil and gas assets for the year ended December 31, 2015 was $21,202,608. The impairment was due to the prolonged decline in the price of oil and gas which changed the recovery economics and expected future revenue of our producing wells and forced us to incur an impairment charge. In addition, a number of our properties were lost to lease expiration in 2015.

 

Liquidity and Capital Resources 

 

Our primary sources of liquidity have previously been oil and gas sales revenue and the sales of certain properties as well as equity contributions from the Acquisition and equity and loans from our founder Jason Hoisager as well as loans from Hauser Holdings, LLC and BBS Capital Fund, LP, affiliates of two of our directors and the Senior Secured Note Facility entered into on September 2, 2014 (the “Notes”). Currently, our only source of liquidity is our ongoing sales of oil and gas. Our primary uses of capital have been the acquisition, development and exploration of oil and natural gas properties. As we pursue reserves and production growth, we regularly consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.

 

The Notes became due on September 2, 2015 and the Company was unable to repay them and is continuing to negotiate with its Senior Lender.

 

 

The rapid and substantial decline in oil prices in the later part of 2014 and in 2015 significantly reduced the amount of revenue we receive per barrel of oil. Approximately 91% of our oil and gas revenue comes from oil sales. This decline has reduced our revenue and, as a result, our cash flow, which limits our operations and could limit our future growth. Our current cash position and current level of operating cash flows is not, in aggregate, adequate to support our current working capital requirements, interest costs and, at the same time, support additional drilling activity. The current oil pricing environment and related conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management is exploring various opportunities to remedy the Company’s liquidity concerns.

 

Liquidity and cash flow

 

We commenced oil and gas exploration activities in 2011 and had a working capital deficit of $24,514,819 as of December 31, 2015 largely consisting of our Notes discussed below, accrued liabilities and advances from affiliates. Our net cash flow for the year ended December 31, 2015 was an increase of $70,470, the components of which are described below. Our net cash flow for the year ended December 31, 2014 was a decrease of $2,115,531. We are not currently drilling any new wells; if we were to resume drilling we might need approximately $40 million to fund our operations during the next twelve months, which will include minimum annual property lease payments, well expenditures and operating costs and expenses, however, if oil prices do not rebound significantly in a short time it is highly unlikely that we will resume drilling or drill at such a high pace. In the event that we begin new drilling operations we may require additional funding in 2016.

 

On September 2, 2014 we sold $16,000,000 of Notes under our $45,000,000 Senior Secured Note Facility, with further sales during the term of the facility to be based upon reserve based performance hurdles. No additional Notes were issued. The Notes became due on September 2, 2015; we were unable to repay them and are continuing to negotiate with our Senior Lender.

 

Additionally, in the event we are able to redeem our offering warrants, they would likely be exercised resulting in the receipt of proceeds up to $20,532,500. There can be no assurance we will redeem the offering warrants.

 

Operating Activities 

 

Net cash used in operating activities was $1,368,294 for the year ended December 31, 2015, as compared to net cash used in operating activities of $3,351,574 for the year ended December 31, 2014. The decrease in cash flows used in operating activities is largely a result of the loss from operations in 2015 increasing over that in 2014 and being offset by increase in accounts payable in 2015 and sale of oil and gas properties in 2014.

 

Investing Activities 

 

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities.

  

We used net cash for investing activities of $501,841 and $13,776,966 for the years ended December 31, 2015 and 2014, respectively. During the year ended December 31, 2014, we received proceeds of $5,665,121 from sales of oil and gas properties. We used cash for investing in oil and natural gas properties in the amounts of $501,841 and $18,945,118 for the years ended December 31, 2015 and 2014, respectively.  We used cash for investing in property and equipment in the amount of $496,969 for the year ended December 31, 2014 and none in 2015. We also invested $25,000 in our affiliate Arabella Operating, LLC to post its operating bond for the Texas Railroad Commission during the year ended December 31, 2014.

 

Financing Activities

 

During the year ended December 31, 2015 we received an aggregate of $1,950,605 in advances from affiliates and shareholders, which are repayable on demand without interest. During the year ended December 31, 2015 we paid $10,000 towards our outstanding term note. During the year ended December 31, 2014 we received $1,300,000 in loans from affiliates of two of our directors. On September 4, 2014 we repaid our loans from BBS Capital Fund, LP and Hauser Holdings, LLC with accrued interest for total repayment of $512,500 and $828,222, respectively.

 

On June 26, 2014 our Chief Executive Officer Jason Hoisager purchased 190,477 of our ordinary shares for $10.50 a share in a private transaction from us.

 

 

Senior Secured Note Facility

 

On September 2, 2014 we entered into a $45,000,000 Senior Secured Note Facility (the “Notes”) with a New York based investor (the “Investor”). The sale of $16,000,000 in Notes occurred on September 2, 2014 with further sales during the term of the facility to be based upon reserve based performance hurdles. No additional Notes were issued. The Notes bear interest at an annual rate of 15%, of which six months was prepaid at close. We paid a 3% origination fee to the Investor and a 5% cash commission to our advisors on the transaction. In conjunction with the sale of the Notes, we issued warrants to purchase 1,300,000 of our ordinary shares at a price of $5.00 per share. The warrants expire on September 2, 2019. The Notes became due on September 2, 2015; we were unable to repay them and are continuing to negotiate with our Senior Lender.

 

On January 21, 2016 we received notice from our Senior Lender that they were declaring the Notes in default as of June 4, 2015. While we do not necessarily believe that additional interest is due, we have recorded an accrued interest charge in the amount of $591,620 at December 31, 2015 to reflect the maximum possible difference between the original Note interest and the default Note interest provisions.

 

The Notes are the senior secured obligations of the Company and, with certain exceptions, are secured by first lien positions on all of the Company’s assets and property.

 

Capital Requirements, Sources of Liquidity and Ability to Continue as a Going Concern

 

We are not currently drilling any new wells; if we were to resume drilling we might need approximately $40 million to fund our operations during the next twelve months, which will include minimum annual property lease payments, well expenditures and operating costs and expenses, however, if oil prices do not rebound significantly in a short time it is highly unlikely that we will resume drilling or drill at such a high pace. In the event that we begin new drilling operations we may require additional funding in 2016.

 

The amount and timing of any capital expenditures is largely discretionary and within our control. We could choose to defer a portion of any planned capital expenditures depending on a variety of factors, including but not limited to raising of outside capital, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

 

Additionally, while some of our capital expenditures will be financed through operations, the majority of these costs will require outside financing.

 

The current oil pricing environment, the amounts due on the Senior Secured Note Facility and related conditions raise substantial doubt about our ability to continue as a going concern. Our ability to continue as a going concern is dependent on our ability to generate revenue from oil and gas operations or asset sales and achieve profitable operations and to generate sufficient cash flow from financing and operations to meet our obligations, as they become payable. We have plans to explore additional alternatives to our existing oil and gas activities to generate revenue in the current oil pricing environment. Although there are no assurances that our plans will be realized we believe that we will be able to continue operations in the future.

 

Critical Accounting Policies 

 

Readers of this report and users of the information contained in it should be aware that certain events may impact our financial results based on the accounting policies in place. The policies we consider to be the most significant are discussed below. 

 

The process of preparing financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect reported amounts of certain assets, liabilities, revenues and expenses. We believe our estimates and assumptions are reasonable; however, actual results may differ materially from such estimates. 

 

The selection and application of accounting policies are an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business. 

 

 

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of its oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. 

 

The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Impairment of oil and gas assets for the year ended December 31, 2015 was $21,202,608. The impairment was due to the prolonged decline in the price of oil and gas which changed the recovery economics and expected future revenue of our producing wells and forced us to incur an impairment charge. In addition, a number of our properties were lost to lease expiration in 2015. No impairment of proved oil and natural gas properties was recorded for year ended December 31, 2014.

 

Oil and Gas Properties

 

The accounting for our business is subject to accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. We follow the successful efforts method that requires that geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well in a field by field basis versus the aggregated “full cost” pool basis under the full cost method. Additionally, gain or loss is generally recognized on all sales of natural gas and oil properties under the successful efforts method. As a result, our financial statements will differ from those of companies that apply the full cost method since we will generally reflect a lower level of capitalized costs as well as a lower oil and gas depreciation, depletion and amortization rate, and we may have exploration expenses that full cost companies do not have. 

 

Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved natural gas and oil reserves. Under the full cost method, a company that maintains the same level of production year over year may report significantly different the depreciation, depletion and amortization expense if estimated remaining reserves or future development costs change significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. 

 

Revenue 

 

We utilize the sales method of accounting for oil and natural gas revenues whereby revenues, net of royalties, are recognized as the production is received by purchasers. The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties. We did not have any significant gas imbalance positions at December 31, 2015 or December 31, 2014.

 

Income Taxes 

 

We were subject to Federal income taxes for 2015 and 2014 but had taxable losses so we did not pay any federal income tax. 

 

We are subject to federal and state income based taxes and we use the asset and liability method to account for income taxes. Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the statements of operations in the period that includes the enactment date. We had no deferred state income taxes for the years 2015 and 2014.

 

Recent Accounting Pronouncements

 

Information on recent accounting pronouncements can be found in Note 4 to the consolidated financial statements included in this Annual Report on Form 10-K.

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

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

 

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

ARABELLA EXPLORATION, INC.

CONSOLIDATED FINANCIAL STATEMENTS

 

INDEX TO FINANCIAL STATEMENTS

 

	Page
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2015 and 2014	F-2
Consolidated Statements of Operations for the Years Ended December 31, 2015 and 2014	F-3
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2015 and 2014	F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015 and 2014	F-5
Notes to Consolidated Financial Statements	F-6

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Audit Committee of the

Board of Directors and Shareholders

of Arabella Exploration, Inc.

 

We have audited the accompanying consolidated balance sheets of Arabella Exploration, Inc. and its Subsidiaries (collectively the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, changes in shareholders’ (deficit) equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Arabella Exploration, Inc. and its Subsidiaries, as of December 31, 2015 and 2014, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3, the Company had an accumulated deficit of $35,961,252 and a working capital deficiency of $24,514,819 as of December 31, 2015 largely consisting of notes payable that are currently in default and due in less than twelve months. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans regarding these matters are described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ Marcum LLP

 

Marcum llp

New York, NY

April 14, 2016

 

 

ARABELLA EXPLORATION, INC.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2015 AND 2014

 

		2015				2014
ASSETS
Current assets:
Cash and cash equivalents		$	73,472			$	3,002
Accounts receivable - oil and gas sales			1,631,735				814,689
Prepaid expenses			-				417,617
Total current assets			1,705,207				1,235,308
Deposits and other assets			67,368				85,000
Receivable from affiliate			-				381,801
Property and equipment, net			132,508				315,826
Oil and gas properties, successful efforts method - Net			6,931,126				28,305,172
Total assets		$	8,836,209			$	30,323,107
LIABILITIES AND SHAREHOLDERS’ (DEFICIT) EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	1,820,209			$	1,001,058
Accrued interest payable			2,191,620				-
Payable to affiliates			1,983,155				32,550
Notes payable, net of discount			16,115,000				11,838,247
Accrued joint interest billings payable, related party			4,109,729				3,382,514
Total current liabilities			26,220,025				16,254,369
Note payable to officer			3,007,170				3,007,170
Asset retirement obligation			24,490				25,843
Total liabilities			29,251,685				19,287,382
Commitments and contingencies
Shareholders’ (deficit) equity
Preferred shares, $0.001 par value, authorized 5,000,000 shares and none issued and outstanding			-				-
Ordinary shares, $0.001 par value, authorized 50,000,000 shares;  issued and outstanding 5,020,303 at December 31, 2015 and 2014			5,020				5,020
Additional paid-in-capital			15,540,755				15,335,684
Accumulated deficit			(35,961,251	)			(4,304,979	)
Total shareholders’ (deficit) equity			(20,415,476	)			11,035,725
Total liabilities and shareholders’ (deficit) equity		$	8,836,209			$	30,323,107

 

The accompanying notes are an integral part of the consolidated financial statements.

 

 

ARABELLA EXPLORATION, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

		2015				2014
Revenues:
Oil and gas revenue		$	1,475,856			$	3,408,296
Other revenue – administrative overhead			39,600				-
Other operating revenue – gain on sale of oil and gas properties			-				3,084,917
Total revenues			1,515,456				6,493,213
Costs and expenses:
Lease operating expenses			1,100,312				1,633,456
Ad valorem and production taxes			73,182				153,231
Depreciation, depletion and amortization			767,116				1,444,315
(Reduction) accretion of asset retirement obligation			(1,353	)			1,770
General and administrative expenses			2,876,348				5,154,056
Impairment of oil and gas properties			21,202,608				-
Total costs and expenses			26,018,213				8,386,827
Loss from operations			(24,502,757	)			(1,893,614	)
Other expense
Interest expense, related party			-				(40,722	)
Interest expense			(7,153,516	)			(2,882,212	)
Other expense			(7,153,516	)			(2,922,934	)
Net loss before taxes			(31,656,273	)			(4,816,548	)
Provision for income taxes			-				-
Net loss		$	(31,656,273	)		$	(4,816,548	)
Net loss per ordinary share:
Basic		$	(6.31	)		$	(0.98	)
Diluted		$	(6.31	)		$	(0.98	)
Weighted average ordinary shares outstanding:
Basic			5,020,303				4,928,978
Diluted			5,020,303				4,928,978

 

The accompanying notes are an integral part of the consolidated financial statements.

 

 

ARABELLA EXPLORATION, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ (DEFICIT) EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

														Retained
														Earnings
		Ordinary								Paid-In				(Accumulated
		Shares								Capital				Deficit)				Total
		Shares				Amount
Balance at December 31, 2013			4,829,826			$	4,830			$	8,488,970			$	511,570			$	9,005,370
Ordinary shares sold to officer			190,477				190				1,999,819				-				2,000,009
Stock based compensation			-				-				391,265				-				391,265
Issuance of warrants in conjunction with Senior Notes financing			-				-				3,237,840				-				3,237,840
Issuance of warrants to transaction advisors			-				-				1,217,790				-				1,217,790
Net loss			-				-				-				(4,816,548	)			(4,816,548	)
Balance at December 31, 2014			5,020,303			$	5,020			$	15,335,684			$	(4,304,978	)		$	11,035,725
Stock based compensation			-				-				205,071				-				205,071
Net loss			-				-				-				(31,656,273	)			(31,656,273	)
Balance at December 31, 2015			5,020,303			$	5,020			$	15,540,755			$	(35,961,251	)		$	(20,415,476	)

 

The accompanying notes are an integral part of the consolidated financial statements.

  

 

ARABELLA EXPLORATION, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

		2015				2014
Cash flows from operating activities:
Net loss		$	(31,656,273	)		$	(4,816,548	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			767,116				1,444,314
Impairment of oil and gas properties			21,202,608				-
(Reduction) accretion of asset retirement obligation			(1,353	)			1,770
Amortization of interest expense			400,000				800,000
Amortization of deferred financing costs			2,003,193				1,001,597
Amortization of debt discount			2,158,560				1,079,280
Stock based compensation			205,071				391,265
Loss on disposal of fixed assets			89,481				48,840
Gain from sale of oil and gas properties			-				(3,084,917	)
Changes in operating assets and liabilities:
Accounts receivable - oil and gas sales			(817,045	)			(377,859	)
Prepaid expenses			17,617				5,460
Deposits and other assets			17,632				(60,000	)
Receivable from affiliated companies			381,801				(381,801	)
Payable to affiliated companies			-				32,550
Accrued joint interest billing payable			727,215				(351,891	)
Accounts payable and accrued liabilities			3,136,084				916,367
Net cash used in operating activities			(1,368,294	)			(3,351,574	)
Cash flows from investing activities:
Additions to property and equipment			-				(496,969	)
Additions to oil and gas properties			(501,841	)			(18,945,118	)
Proceeds from sale of oil and gas properties			-				5,665,121
Net cash used in investing activities			(501,841	)			(13,776,966	)
Cash flows from financing activities:
Proceeds from sale of ordinary shares to officer			-				2,000,009
Proceeds from Senior Secured Notes			-				16,000,000
Proceeds from Directors’ Loans			-				1,300,000
Repayment of Directors’ Loans			-				(1,300,000	)
Repayment of Term Note			(10,000	)			-
Prepaid Interest, Senior Secured Notes			-				(1,200,000	)
Deferred financing cost			-				(1,787,000	)
Proceeds from advances from affiliates			1,950,605				-
Net cash provided by financing activities			1,940,605				15,013,009
Net increase (decrease) in cash and cash equivalents			70,470				(2,115,531	)
Cash and cash equivalents at beginning of year			3,002				2,118,533
Cash and cash equivalents at end of year		$	73,472			$	3,002
Cash for:
Interest		$	200,000			$	40,722
Taxes		$	-			$	-
Non-cash investing and financing activities:
Addition to deferred financing costs		$	-			$	3,004,790
Addition to oil and gas properties through increase in accrued joint interest billings payable		$	131,298			$	428,321
Accrued liability converted to term note		$	125,000			$	-

 

The accompanying notes are an integral part of the consolidated financial statements.

 

ARABELLA EXPLORATION, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMNTS

 

1. Organization and Operations of the Company

 

Organization

 

Arabella Exploration, Inc. (formerly known as Lone Oak Acquisition Corporation) (the “Parent”) was incorporated in the Cayman Islands on June 17, 2010 as a blank check company whose objective was to acquire an operating business. Parent’s wholly owned subsidiary Arabella Exploration, LLC (“Arabella LLC”) was formed in 2011, to acquire interests in low risk prospective and producing oil and gas properties primarily in the Permian Basin in West Texas. The Parent and Arabella LLC (collectively the “Company”) completed a reverse merger on December 24, 2013 as more fully described below in Note 2.

 

AEX Operating, LLC (“AOC”), a wholly owned subsidiary of the Parent, was formed in 2014 to assume the operations role for the Parent. AOC posted a surety bond with the Texas Railroad Commission and is the operator of record for the Company’s oil and gas properties as of December 31, 2014. Prior to December 31, 2014 Arabella Petroleum Company, LLC, an affiliate of Jason Hoisager, the Parent’s Chief Executive Officer was the operating of record for the Company’s acreage.

 

Nature of Business

 

The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources in the Permian Basin in West Texas. The Company owns acreage leases and participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital intensive nature of oil and natural gas drilling activities, the operating company responsible for conducting the drilling operations may request advance payments from the working interest partners for their share of the costs.

 

2. Reverse Merger

 

Parent and Arabella LLC (the wholly owned subsidiary) entered into a reverse merger on December 24, 2013 where the Parent issued 3,125,000 ordinary shares to the holders of all of the issued and outstanding interests of Arabella LLC immediately prior to the time of the Acquisition in exchange for 100% of the units of Arabella LLC. In connection with the reverse merger, 1,704,826 of the Parent’s ordinary shares remained outstanding and the remaining funds in the trust account, in the amount of $5,183,417, were distributed to the Parent. With that exchange, the Company’s Chief Executive Officer Jason Hoisager owns the majority of the Company’s ordinary shares. In connection with the reverse merger, 1,705,002 of additional ordinary shares (“earnout shares”) will be awarded to certain individuals associated with Arabella LLC over the following three years if the Company achieves its earnout goals. The shares will be issued in equal thirds if on each of December 31, 2014, 2015 and 2016 the Company shall have increased its proved reserves over the immediately preceding year by 100%, 66% and 33%, respectively and conforms with certain cost metrics. The Company has not determined the ultimate disposition of these shares for 2015 or 2014.

 

The merger was accounted for as a “reverse merger” and a recapitalization since the shareholders of Arabella LLC (i) owned a majority of the outstanding ordinary shares of the Company immediately following the completion of the transaction, and (ii) have the significant influence and the ability to elect or appoint or to remove a majority of the members of the governing body of the combined entity, and Arabella LLC’s senior management dominates the management of the combined entity in following the completion of the transaction in accordance with the provision of Financial Accounting Standards Board Accounting Standards Codification (“FASB-ASC”) Topic 805 Business Combinations. Accordingly, Arabella LLC is deemed to be the accounting acquirer in the transaction and, consequently, the transaction is treated as a recapitalization of Arabella LLC. Accordingly, the assets and liabilities and the historical operations that are reflected in the financial statements are those of Arabella LLC and are recorded at the historical cost basis of Arabella LLC. Parent’s assets, liabilities and results of operations were consolidated with the assets, liabilities and results of operations of Arabella LLC after the merger.

 

 

3. Recent Developments, Liquidity and Ability to Continue as a Going Concern

 

The accompanying financial statements have been prepared in US dollars and in accordance with accounting principles generally accepted in the United States of America on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. The Company commenced oil and gas exploration activities in 2011 and at December 31, 2015 had an accumulated deficit of $35,961,252 and a working capital deficit of $24,514,819 largely consisting of notes payable due in less than twelve months as well as accounts payable and advances from affiliates. The Company is not currently engaged in any new drilling for oil and gas due to the depressed price for oil. The current oil pricing environment and related conditions raise substantial doubt about the Company’s ability to continue as a going concern. The Company’s ability to continue as a going concern is dependent on its ability to generate revenue from oil and gas operations or asset sales and achieve profitable operations and to generate sufficient cash flow from financing and operations to meet its obligations, as they become payable.

 

Management has plans to explore additional alternatives to its existing oil and gas activities to generate revenue in the current oil pricing environment. Although there are no assurances that management’s plans will be realized management believes that the Company will be able to continue operations in the future. Accordingly, no adjustment relating to the recoverability and classification of recorded asset amounts and the classification of liabilities has been made to the accompanying financial statements in anticipation of the Company not being able to continue as a going concern. The Company entered into a Purchase and Sale Agreement with a third party buyer (“Buyer”), dated as of July 1, 2015, and a letter agreement with McCabe Petroleum Corporation (“McCabe”), dated as of April 15, 2015, pursuant to which the Company would sell its ownership interest in certain of its properties for cash and properties. Pursuant to the agreements, the transactions would have closed simultaneously and the Company would transfer its Locker State, Graham, Woods, Jackson and Emily Bell prospects to the Buyer and would have received cash from the Buyer and certain properties from McCabe. On September 1, 2015, the Company received a text message and email from the Buyer terminating the PSA pursuant to Section 13.1 of the PSA. The Buyer cited several items to justify its unexpected cancelation of the PSA including a number of standard closing information items as well as certain third party approvals that had not been obtained as of that date. The letter agreement with McCabe remains in place but is dependent on a transaction similar to the one contemplated in the PSA being consummated simultaneously. The Company is currently searching for such a replacement or another strategic alternative.

 

The Company is not currently drilling any new wells; if it were to resume drilling it might need approximately $40 million to fund its operations during the next twelve months, which would include minimum annual property lease payments, well expenditures and operating costs and expenses, however, if oil prices do not rebound significantly in a short time it is highly unlikely that it will resume drilling or drill at such a high pace. In the event that it begins new drilling operations it may require additional funding in 2016.

 

On September 2, 2014 the Company sold $16,000,000 of Notes under its $45,000,000 Senior Secured Note Facility (See Note 8 – Senior Secured Notes), with further sales during the term of the facility to be based upon reserve based performance hurdles. No additional Notes were issued. The Notes were due on September 2, 2015; the Company was unable to repay them and is continuing to negotiate with its Senior Lender. On January 21, 2016 the Company received notice from its Senior Lender that they were declaring the Notes in default as of June 4, 2015.

 

Additionally, in the event that the Company is able to redeem its initial public offering warrants as discussed in Note 11 – Shareholders Equity, the initial public offering warrants would likely be exercised resulting in the receipt of proceeds up to $20,532,500 to further sustain the Company’s operations. There can be no assurance that the Company will redeem the initial public offering warrants.

 

4. Summary of Significant Accounting Policies

 

Principals of Consolidation

 

The accompanying consolidated financial statements of the Company include the accounts of Arabella Exploration Inc. and its wholly owned subsidiaries Arabella Exploration, LLC, Arabella Operating, LLC and Arabella Midstream, LLC. All significant intercompany transactions have been eliminated in consolidation.

 

Revised Prior Period Amounts

 

The Company revised the presentation of oil and gas properties, successful efforts method - net, notes payable, net of discount and accrued joint interest billings payable – related party in its consolidated balance sheet for the year ending December 31, 2014 to reverse the effect of an over-accrual of joint interest billings payable – related party in the amount of $737,974, more fully discussed in Note 7 and to reflect a $125,000 liability as described more fully in Note 10. Tabular summaries of the revisions are presented below:

 

		Consolidated Balance Sheet December 31, 2014
		Previously Reported				Revisions				Revised Reported
Oil and gas properties, successful efforts method - net		$	29,043,146			$	(737,974	)		$	28,305,172
Accounts payable and accrued liabilities			876,058				125,000				1,001,058
Accrued joint interest billings payable, related party			4,120,488				(737,974	)			3,382,514
Accumulated deficit			(4,179,979	)			(125,000	)			(4,304,979	)

 

 

		Consolidated Statement of Operations Year ended December 31, 2014
		Previously Reported				Revisions				Revised Reported
Net loss		$	(4,691,549	)		$	(125,000	)		$	(4,816,549	)
Net loss per ordinary share:
Basic		$	(0.95	)		$	(0.03	)		$	(0.98	)
Diluted		$	(0.95	)		$	(0.03	)		$	(0.98	)

 

The Company analyzed the revisions under SEC staff guidance (Staff Accounting Bulletin 108) and determined that the revisions are immaterial on a quantitative and qualitative basis and that it is probable that the judgment of a reasonable person relying upon the financial statements would not have been changed or influenced by the inclusion or correction of the items in the year ended December 31, 2014. Therefore, amendment of the previously filed annual report on Form 10-K is not considered necessary. However, if the adjustments to correct the errors were recorded in the first quarter of 2015, the Company believes the impact would have been significant to the first quarter and would impact comparisons to prior periods. The Company has also revised in this current Form 10-K filing the previously reported annual financial statements for 2014 on Form 10-K for these amounts.

 

Use of Estimates

 

Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain oil and natural gas revenues and expenses, estimates of the valuation allowance for deferred tax assets and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.

 

As an oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.

 

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization expense, dismantlement and abandonment costs, and impairment expense.

 

Cash and Cash Equivalents

 

The Company considers all highly liquid investments purchased with a maturity of three months or less when purchased and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

 

 

Accounts Receivable

 

Accounts receivable consist of receivables from the operators for properties in which the Company has working interests for the oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the operator, then the operator allocates the revenue based on the working interest of the owners.  The Company generally receives its share of the working interest revenue within three months after the production month.

 

Accounts receivable are stated at amounts based on the percent revenue working interest due from the purchasers that goes through the operator of the property, net of an allowance for doubtful accounts when the Company believes collection is doubtful.  Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2015 or 2014.

 

Property and Equipment

 

Property and equipment include furniture and fixtures, computer equipment and software and transportation equipment. These items are recorded at cost and are depreciated using the straight-line method based on lives of the individual assets ranging from one to seven years. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations.

 

Oil and Gas Properties

 

Proved Oil and Gas Properties

 

Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.

 

The provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.

 

Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case a gain or loss is recognized currently.

 

Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

 

The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed in Note 5 — Fair Value Measurements. Impairment of oil and gas assets for the year ended December 31, 2015 was $21,202,608. The impairment was due to the prolonged decline in the price of oil and gas which changed the recovery economics and expected future revenue of the Company’s producing wells resulting in an impairment charge. In addition, a number of the Company’s properties were lost to lease expiration in 2015. No impairment of proved oil and natural gas properties was recorded for the year ended December 31, 2014.

 

 

Unproved Oil and Gas Properties

 

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment of oil and gas properties in the Consolidated Statement of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

 

The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:

 

●

the remaining amount of unexpired term under its leases;

 

●

its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;

 

●

its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

 

●

its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

 

●

its evaluation of the continuing successful results from the application of completion technology in the Bone Spring and Wolfcamp  formations by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.

 

For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

 

Exploration Expenses

 

Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.

 

Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. As of December 31, 2015 and 2014, the Company had no exploratory well costs.

 

Asset Retirement Obligations

 

In accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company’s Consolidated Statement of Operations.

 

The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.  These assumptions represent Level 3 inputs, as further discussed in Note 5 — Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

 

 

Revenue Recognition

 

Oil and gas revenue from the Company’s interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of the Company’s production is sold to purchasers under short-term (less than twelve months) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, the Company sells the majority of its production soon after it is produced. As a result, the Company maintains a minimum amount of product inventory in storage.

 

Accounting for Stock-Based Compensation

 

The Company grants stock options to the members of its Board of Directors. These plans and related accounting policies are defined and described more fully in Note 13—Shareholders’ Equity. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.

 

Production Taxes

 

The Company pays taxes and royalties on oil and natural gas in accordance with the laws and regulations applicable to those agreements.

 

Concentrations of Market and Credit Risk

 

The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

 

The Company operates in the exploration, development and production sector of the oil and gas industry. The Company’s receivables include amounts due from purchasers of its oil and natural gas production. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. 

 

Environmental Costs

 

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

 

Income Taxes

 

Arabella Exploration, Inc. has identified the Cayman Islands as its only “major” tax jurisdiction, as defined.  Arabella Exploration, Inc. has received an undertaking from the Governor-in-Cabinet of the Cayman Islands that, in accordance with section 6 of the Tax Concessions Law (Revised) of the Cayman Islands, for a period of 20 years from the date of the undertaking, no law which is enacted in the Cayman Islands imposing any tax to be levied on profits, income, gains or appreciations shall apply to Arabella Exploration, Inc. or its operations and, in addition, that no tax to be levied on profits, income, gains or appreciations or which is in the nature of estate duty or inheritance tax shall be payable (i) on the Company’s securities or our debentures or other obligations or (ii) by way of the withholding in whole or in part of a payment of dividend or other distribution of income or capital by Arabella Exploration, Inc. to its security holders or a payment of principal or interest or other sums due under a debenture or other obligation.

 

Based on the Company’s evaluation, it has been concluded that there are not significant uncertain tax positions requiring recognition in the Company’s financial statements.  Since Arabella Exploration, Inc. was incorporated on June 17, 2010, the evaluation was performed for the 2010, 2011 and 2012 tax years which will be the only periods subject to examination.  The Company believes that its income tax positions and deductions would be sustained on audit and does not anticipate any adjustments that would result in material changes to its financial position.

 

 

During 2013, 2012 and 2011, Arabella, LLC was not a taxable entity for federal income tax purposes. Accordingly, Arabella did not directly pay federal income tax. Arabella, LLC’s taxable income or loss, which may vary substantially from the net income or net loss Arabella, LLC’s reports in Arabella Exploration, Inc.’s consolidated statement of income, is includable in the federal income tax returns of the member.

 

During 2015 and 2014, Arabella Exploration, LLC was a taxable entity for federal income tax purposes as more fully described in Note 16 – Income Taxes.

 

Fair Value of Financial and Non-Financial Instruments

 

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and other payables approximate their respective fair market values due to their short-term maturities. At December 31, 2015 the Company’s cash equivalents are Level 1 assets. The Company’s asset retirement obligations are also recorded on the Consolidated Balance Sheet at amounts which approximate fair market value. See Note 5 — Fair Value Measurements.

 

The Senior Secured Notes were carried at cost, less the debt discount incurred related to the fair value of the warrants issued in conjunction with the sale of the Senior Secured Notes at December 31, 2014. The Senior Secured Notes are carried at their full face value as of December 31, 2015 as the debt discount has been fully amortized. See Note 9 – Senior Secured Notes.

 

Earnings per Share

 

Basic earnings per share is computed by dividing net income available to shareholders by the weighted average number of shares outstanding for the periods presented. Fully diluted earnings per share is computed by dividing net income available to shareholders by the weighted average number of fully diluted shares outstanding for the periods presented. See Note 17 – Earnings Per Share

 

Recent Accounting Pronouncements

 

The Financial Accounting Standards Board (“FASB”) has issued Accounting Standards Update (“ASU”) No. 2014-12, Compensation – Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This ASU requires that a performance target that affects vesting, and that could be achieved after the requisite service period, be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. This update further clarifies that compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. The amendments in this ASU are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial position and results of operations. The Company has elected early adoption of this standard.

 

In August 2014, the FASB issued ASU No. 2014-15, "Disclosures of Uncertainties About an Entity's Ability to Continue as a Going Concern". The new standard provides guidance around management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Early adoption is permitted. The Company does not expect that this guidance will have a material impact on its financial position, results of operations or cash flows. The Company has elected early adoption of this standard.

 

The FASB has issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this ASU require that debt issuance costs related to a debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs have not changed.

 

In May 2014, the FASB issued ASU No. 2014-09, which creates Topic 606, Revenue from Contracts with Customers, and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, ASU 2014-09 supersedes the cost guidance in Subtopic 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts, and creates new Subtopic 340-40, Other Assets and Deferred Costs— Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The amendments in ASU 2014-09 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, and early application is permitted commencing January 1, 2017. The Company is currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on its financial position and results of operations.

 

 

In November 2015, the FASB has issued an update to ASU No. 2015-17 “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes.” The update requires a company to classify all deferred tax assets and liabilities as noncurrent. The update of ASU 2015-17 is effective for us on January 1, 2018. The Company does not expect the adoption of the update of ASU 2015–17 to have a significant impact on its financial statements.

 

In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” ASU 2016-02 requires a lessee to recognize a lease liability for the obligation to make lease payments and a right-to-use asset for the right to use the underlying asset for the lease term. ASU 2016-02 is effective for us on January 1, 2019. Early adoption is permitted. The Company is currently evaluating the effect that ASU 2016-02 will have on its financial statements and related disclosures.

 

5. Fair Value Measurements

 

In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis.

 

As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

 

The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:

 

Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

 

Level 3 — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

 

Nonfinancial Assets and Liabilities

 

Asset retirement obligations. The carrying amount of the Company’s Asset Retirement Obligations, or ARO, in the Consolidated Balance Sheet at December 31, 2015 is $24,490 (see Note 8 — Asset Retirement Obligations). The Company determines the ARO by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

 

 

Impairment. The Company reviews its proved oil and natural gas properties on a field by field basis for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such amounts to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. Impairment of oil and gas assets for the year ended December 31, 2015 was $21,202,608. The impairment was due to the prolonged decline in the price of oil and gas which changed the recovery economics and expected future revenue of the Company’s producing wells resulting in an impairment charge. In addition, a number of the Company’s properties were lost to lease expiration in 2015. No impairment charges on proved oil and natural gas properties were recorded for the year ended December 31, 2014.

 

6. Property and Equipment

 

Property and equipment include furniture and fixtures, computer equipment and software and transportation equipment:

 

		December 31,				December 31,
		2015				2014
Property and equipment, gross		$	346,199			$	435,679
Less: Accumulated depreciation and amortization			(213,691	)			(119,853	)
Property and Equipment, net		$	132,508			$	315,826

 

Depreciation expense was $128,416 and $132,303 for the years ended December 31, 2015 and 2014, respectively.

 

The Company disposed of two vehicles in 2015 with a net book value of $54,902 for $23,000 resulting from a loss on sale of asset of $31,902 which was accounted for in General and Administrative expenses.

 

Effective January 1, 2016 the Company transferred certain of its fixed assets to a third party management company in return for the forgiveness of certain indebtedness. The gross book value of the assets was $293,893 and they were appraised at under $50,000 in current conditions. The Company currently leases this equipment for its use from that third party management company, inclusive of utilities and other office expenses for $12,500 per month.

 

7. Oil and Gas Properties

 

The following table sets forth the Company’s oil and gas properties: 

 

		December 31,
		2015				2014
Proved oil and gas properties (1)		$	22,316,760			$	25,168,514
Less: Accumulated depreciation, depletion, amortization and impairment (2)			(20,171,564	)			(1,763,731	)
Proved oil and gas properties, net			2,145,196				23,404,783
Unproved oil and gas properties			4,785,930				4,900,389
Total oil and gas properties, net		$	6,931,126			$	28,305,172

 

(1)   (2)

Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $21,105 and $23,575 at December 31, 2015 and 2014, respectively. Included in the depreciation, depletion, amortization and impairment is depletion of $673,278 and $1,312,012 in 2015 and 2014, respectively.

 

The Company recorded impairment of oil and gas assets for the year ended December 31, 2015 of $21,202,608, which includes impairment of existing wells of $17,734,554 and the loss of $3,468,054 in other properties. The Impairment was due to the prolonged decline in the price of oil and gas which changed the recovery economics and expected future revenue of the Company’s producing wells resulting in an impairment charge. In addition, a number of the Company’s properties were lost to lease expiration in 2015.

 

 

The Company accrued certain amounts during 2014 to reflect estimated spending on oil and gas leases based upon the overall spending during 2014. As a result of declining oil prices, those amounts were overestimated and the Company revised certain accruals for the year ended December 31, 2014. The preceding table reflects the revisions described in Note 4.

 

8. Asset Retirement Obligations

 

The following table reflects the changes in the Company’s ARO during the years ended December 31, 2015 and 2014:

 

		Year Ended December 31,
		2015				2014
Asset retirement obligation — beginning of period		$	25,843			$	21,171
Additions to ARO from new properties			--				6,030
Sales or abandonments of properties			(3,273	)			(3,128	)
Accretion expense during period			1,920				1,770
Asset retirement obligation — end of period		$	24,490			$	25,843

 

9. Senior Secured Notes

 

On September 2, 2014 the Company entered into a $45,000,000 Senior Secured Note Facility with a one year borrowing period and a one year term per draw (the “Notes”) with a New York based investor (the “Investor”). The sale of $16,000,000 in Notes occurred on September 2, 2014 with further sales to be based upon reserve based performance hurdles. No additional Notes were issued. The Notes bear interest at an annual rate of 15%, of which six months was prepaid at close. The Notes are due one year from the issuance date and can be redeemed by the Company at any time without penalty. The Notes became due on September 2, 2015; the Company was unable to repay them and is continuing to negotiate with its Senior Lender. The Company paid a 3% origination fee to the Investor and a 5% cash commission to its advisors on the transaction. In conjunction with the sale of the Notes, the Company issued warrants to purchase 1,300,000 of the Company’s ordinary shares at a price of $5.00 per share (the “Financing Warrants”). The Financing Warrants expire on September 2, 2019.

 

The Senior Secured Notes are carried at December 31,2015 and 2014 at their face value less the amortized amount of the debt discount associated with the relative fair value at issuance of the Financing Warrants. The fair value of the Financing Warrants at issue was determined to be approximately $4,059,300 using the Black-Scholes pricing model. Significant assumptions used in the valuation include an expected term of 5 years, an expected volatility of 51.0% based on historical value and corresponding volatility of the Company’s peer group stock price for a period consistent with the warrants expected term, a risk free interest rate of 1.69% based on the a U.S. Treasury Note with a similar term to the expected term on the date of the grant, and an expected dividend yield of 0.0% as the Company does not expect to pay dividends in the near future. The Relative Fair Value of the Financing Warrants was then determined by applying the ratio of value of the Notes to the value of the Notes plus the fair value of the Financing Warrants to the amount of the Notes. Using this metric, the relative fair value of the Financing Warrants was determined to be $3,237,840. The debt discount is amortized using the straight line method over the one year term of the Notes. As of September 2, 2015, the Notes became due and the debt discount has been fully amortized, as such the Notes are presented at their full face value as of December 31, 2015.

 

The Company has elected early adoption of accounting Standards Update (ASU) No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as such deferred financing costs, net of amortization in the amount of $2,003,193 do not appear in current assets and are instead netted against the face value of the Notes.

 

		December 31,
		2015				2014
Senior Secured Notes Payable		$	16,000,000			$	16,000,000
Less:
Debt discount – warrants			(3,237,840	)			(3,237,840	)
Deferred financing costs			(3,004,790	)			(3,004,790	)
Add:
Accretion of debt discount			3,237,840				1,079,280
Amortization of deferred financing cost			3,004,790				1,001,597
Senior Secured Notes Payable, net of discount		$	16,000,000			$	11,838,247

 

 

Interest expense for the year ended December 31, 2015 was a total of $7,153,373 consisting of $2,991,620 of interest expense (including an accrual of $591,620 in possible penalty rate interest) and $2,158,560 of accretion of the debt discount. Amortization of deferred financing costs was $2,003,193 for the same period. Interest expense for the year ended December 31, 2014 was a total of $2,880,877 consisting of $800,000 of interest expense and $1,079,280 of accretion of the debt discount. Amortization of deferred financing costs was $1,001,597 for the same period. Pending discussions with its Senior Lender concerning the disposition of the Notes, the Company continued to accrue $200,000 per month in interest expenses based on the 15% interest rate on the Notes.

 

On January 21, 2016 the Company received notice from its Senior Lender that they were declaring the Notes in default as of June 4, 2015. While the Company does not necessarily believe that additional interest is due, it has recorded an additional accrued interest charge in the amount of $591,620 at December 31, 2015 to reflect the maximum possible difference between the original Note interest and the default Note interest provisions.

 

10. Term Note

 

On May 4, 2015 the Company reached a settlement agreement to pay Heartland Bank (“Heartland”) $125,000 to settle Heartland’s demands that the Company pay a break-up fee and certain costs relating to a financing that the Company explored with Heartland but ultimately rejected in favor of other financing. Under the settlement, the Company issued Heartland a $250,000 non-interest bearing Term Note (the “Term Note”) and agreed to pay $10,000 on the 15^th of every month towards that note. However, the full face amount of the Term Note is intended only to be punitive in the event of non-compliance and, upon the maturity of the Senior Secured Notes, the Company will pay an amount of $125,000, less payments made to date, in full satisfaction of the Term Note. The Term Note is not interest bearing. The Company made $10,000 in payments on the Term Note in 2015 leaving a $115,000 balance; the final disposition of the Term Note has not been determined.

 

Because the events leading to the Heartland lawsuit occurred during 2014, the Company has accounted for the liability as if it had been incurred during the year ended December 31, 2014 and adjusted its financials accordingly as described in Note 4.

 

11. Notes Payable to Directors

 

On May 1, 2014 the Company received a loan from Hauser Holdings, LLC an affiliate of Richard Hauser, one of our directors.  The $800,000 loan was due August 31, 2014 and bears an interest rate of 10% per annum.

 

On June 10, 2014 the Company received a loan from BBS Capital Fund, LP an affiliate of Berke Bakay, one of our directors.  The $500,000 loan was due August 31, 2014 and bears an interest rate of 10% per annum.

 

On September 4, 2014 the Company repaid its loans from BBS Capital Fund, LP and Hauser Holdings, LLC with accrued interest for total repayment of $512,500 and $828,222, respectively.

 

12. Note Payable to Officer

 

As of December 31, 2015 and 2014, the Company’s note payable to officer is payable to Jason Hoisager, the founder of Arabella Exploration, LLC, with an outstanding balance of $3,007,170. The founder is currently the President of the Company and is a director and majority shareholder of the Company. The note payable is non-interest bearing and matures in December of 2023.

 

13. Shareholders’ Equity

 

The Company is authorized to issue 50,000,000 ordinary shares and 5,000,000 preferred shares with a par value of $0.001 per share.

 

Ordinary Shares

 

On June 26, 2014 the Company’s Chief Executive Officer Jason Hoisager purchased 190,477 of the Company’s ordinary shares for $10.50 per share for an aggregate of $2,000,009 in a private placement.

 

 

Preferred Shares

 

The Company is authorized to issue up to 5,000,000 preferred shares with a par value of $0.001 and the characteristics of the preferred shares will be determined by the Board of Directors of the Company from time to time.

 

Warrants

 

In connection with Parent’s Offering in March 2011, the Company issued 4,106,500 offering warrants, which entitles the holders to purchase ordinary shares at the price of $5.00 per share, commencing on the date of the business combination, if the Company has an effective and current registration statement covering the ordinary shares issuable upon exercise of the initial public offering warrants and a current prospectus relating to such ordinary shares, and expiring three years from that date.  The Company may redeem the initial public offering warrants at a price of $0.01 per initial public offering warrant upon 30 days’ notice while the initial public offering warrants are exercisable, only when the last sale price of the ordinary shares is at least $10.50 per share for any 20 trading days within a 30 trading day period, provided that a current registration statement is in effect for the ordinary shares underlying the initial public offering warrants.  If not exercised, the initial public offering warrants expire on December 24, 2016.  If the Company redeems the initial public offering warrants, management of the Company will have the option to require any holder that wishes to exercise his initial public offering warrants to do so on a cashless basis.

 

Simultaneously with the Offering, certain of the shareholders purchased 6,600,000 insider warrants at the price of $0.35 per insider warrant (for an aggregate purchase price of $2,310,000) from the Company.  These insider warrants have the same terms as the 4,106,500 initial public offering warrants referred to in the preceding paragraph, except these insider warrants are not redeemable and the insider warrants are exercisable for cash or on a cashless basis.

 

In conjunction with the sale of the Notes, the Company issued the Financing Warrants to purchase 1,300,000 of the Company’s ordinary shares at a price of $5.00. The Financing Warrants expire on September 2, 2019.

 

Unit Purchase Option

 

In connection with the Offering, the Company issued unit purchase options to purchase an aggregate of 400,000 units at an exercise price of $8.80 per unit to its underwriters and designees of the underwriter.  Each unit consists of one ordinary share and one redeemable ordinary share purchase warrant, which contains a provision for cashless exercise and has the same terms as the 4,106,500 initial public offering warrants.  The unit purchase option expires on December 24, 2018.

 

Stock-based Compensation

 

On May 5, 2014 the Company granted each non-employee director 30,000 stock options to purchase its ordinary shares for joining the board and 20,000 stock options to purchase its ordinary shares for each year of service commencing from January 30, 2014. All 50,000 stock options, in aggregate, vest ratably over two years and expire five years from the grant date. The stock options have an exercise price of $6.15 per share, which represents the closing price of the Company’s ordinary shares the day prior to the grant. The grant date fair value of the options granted was determined to be approximately $558,950 using the Black-Scholes pricing model. Significant assumptions used in the valuation include an expected term of 3.5 years utilizing the “Simplified Method” as the Company does not have sufficient historical experience to estimate an expected term, an expected volatility of 49.0% based on historical value and corresponding volatility of the Company’s peer group stock price for a period consistent with the stock option expected term, a risk free interest rate of 0.9% based on the a U.S. Treasury Note with a similar term to the expected term on the date of the grant, and an expected dividend yield of 0.0% as the Company does not expect to pay dividends in the near future. According to the terms of the option plan, vesting was retroactive to the beginning of service in January 2014; as such two quarters of vesting was recorded during the three months ended June 30, 2014. Messrs. Bush and Boyuls, two of the directors, resigned from the board on September 9, 2014. The remaining members of the board voted to allow them to continue in the vesting of their granted stock options as if they had served out their term. However, as no further service is required for the vesting, the Company expensed the entire amount of the grant in 2014. Accordingly, aggregated stock-based compensation expense for the years ended December 31, 2015 and 2014 was $167,685 and $391,265, respectively. Unrecognized compensation expense as of December 31, 2015 and 2014, relating to non-vested common stock options is approximately $0 and $167,685, respectively as all the options had vested by the fourth quarter of 2015. At December 31, 2015 and 2014, no options had been exercised and no options had been forfeited. As of December 31, 2015 and 2014 the aggregate intrinsic value of these options was $0.

 

 

On February 2, 2015 the Company granted each non-employee director 20,000 stock options to purchase its ordinary shares for the year of service commencing from January 30, 2015. All 20,000 stock options vest ratably over two years on a quarterly basis and expire five years from the grant date. The stock options have an exercise price of $3.35 per share, which represents the closing price of the Company’s ordinary shares the day prior to the grant date. The grant date fair value of the options granted was determined to be $74,772 using the Black-Scholes pricing model. Significant assumptions used in the valuation include an expected term of 3.5 years utilizing the “Simplified Method” as the Company does not have sufficient historical experience to estimate an expected term, an expected volatility of 51.0% based on historical value and corresponding volatility of the Company’s peer group stock price for a period consistent with the stock option expected term, a risk free interest rate of 0.8% based on the a U.S. Treasury Note with a similar term to the expected term on the date of the grant, and an expected dividend yield of 0.0% as the Company does not expect to pay dividends in the near future. Aggregated stock-based compensation expense under the 2015 grant for the year ended December 31, 2015 was $37,386. Unrecognized compensation expense as of December 31, 2015, relating to non-vested common stock options is $37,386 and is expected to be recognized through the fourth quarter of 2016. At December 31, 2015, no options had been exercised and no options had been forfeited. As of December 31, 2015 the aggregate intrinsic value of these options was $0.

 

A summary of stock option activity for the years ended December 31, 2015 and 2014 is presented below:

 

		Number of Options				Weighted Average Exercise Price
Outstanding at December 31, 2013			-				-
Granted			250,000			$	6.15
Forfeited			-				-
Exercised			-				-
Outstanding at December 31, 2014			250,000			$	6.15
Exercisable at December 31, 2014			125,000			$	6.15

  

		Number of Options				Weighted Average Exercise Price
Outstanding at December 31, 2014			250,000				6.15
Granted			60,000			$	3.35
Forfeited			-				-
Exercised			-				-
Outstanding at December 31, 2015			310,000			$	5.61
Exercisable at December 31, 2015			280,000			$	5.85

 

14. Related Party Transactions

 

Mr. Jason Hoisager, the Company’s Chief Executive Officer, owns 100% of Arabella Petroleum Company LLC (“Petroleum”), which was the operating company for substantially all the wells that the Company has its working interest in.   As Petroleum drilled and completed the wells, Petroleum billed the Company for its working ownership percentage of the capital costs.  After the completion of each well, Petroleum sold the oil and gas and provided the Company its working interest revenue, net of production taxes and charges for the lease operating expenses. Petroleum is currently in bankruptcy as further discussed in Note 19 – Commitments and Contingencies.

 

As of December 31, 2015 and 2014, the Company owed Petroleum $2,894,396 and $3,382,514, respectively, in joint interest billings to vendors for the well costs. During the year ended December 31, 2014, the Company paid Petroleum $17,072,542 in capital costs for the wells. Petroleum was responsible for collecting the revenue from the purchasers and providing the Company its accounts receivable, which totaled $814,689 at December 31, 2014. As of December 31, 2014 Petroleum owed the Company $381,801, a portion of the costs from the expense sharing agreement between the companies. As of December 31, 2014, Petroleum has ceased to provide these services to the Company and Arabella Operating, LLC, a wholly owned subsidiary of the Company, is the operator of record for the Company’s wells.

 

The Company has a month to month consulting agreement with an affiliate of one of its directors to provide certain financial and operation services for $24,584 per month.

 

During the year ended December 31, 2015, advances of $1,950,605 were received from affiliates of the Company’s CEO and other shareholders. These advances are Non-interest bearing and payable on demand.

 

15. Other Operating Revenue – Gain on Sale of Oil and Gas Properties

 

During the year ended December 31, 2014, Arabella sold undeveloped leased acreage for $5,337,388 in cash and recognized a gain on the sale of the properties of $3,038,261.

 

During the year ended December 31, 2014, Arabella sold developed, non-operated leased acreage for $327,734 in cash and recognized a gain on the sale of the properties of $46,398.

 

Total acreage sales resulted in $5,665,121 in proceeds and gains of $3,084,917 for year ended December 31, 2014. The Company did not sell any acreage in 2013.

 

 

16.    Income Taxes

 

As of December 23, 2013, Arabella Exploration, LLC elected to be treated as a corporation for tax purposes. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

 

The Company had no income tax expense due to operating losses incurred for the years ended December 31, 2015 and 2014.

 

The following is a reconciliation between the federal income tax benefit computed at the statutory federal income tax rate of 34% and actual income tax provision for the years ended December 31, 2015 and December 31, 2014, taking into account the reclassified amounts as described in Note 4 – Summary of Significant Accounting Principles – Revised Prior Period Amounts:

 

		Year Ended December 31,
		2015				2014
Federal income tax benefit at statutory rate			(10,763,133	)			(1,637,592	)
State taxes, net of Federal benefit			18,940				107,927
Permanent differences			504				1,624
Other			-				(307	)
Change in valuation allowance			10,743,689				1,528,348
Provision for income taxes			-				-

 

The tax effects of temporary differences that gave rise to significant portions of deferred tax assets and liabilities at December 31, 2015 and December 31, 2014 are as follows:

		December 31,
		2015				2014
Deferred tax assets:
Net operating loss carryforward		$	18,934,497			$	7,196,141
Stock compensation			206,690				135,613
Deferred tax liabilities:
Fixed Assets			(96,431	)			(53,011	)
Intangible drilling and other costs for oil and gas properties			(6,772,719	)			(5,750,395	)
Net deferred tax assets and liabilities			12,272,037				1,528,348
Less valuation allowance			(12,272,037	)			(1,528,348	)
Total deferred tax assets and liabilities		$	-			$	-

 

The Company had a net deferred tax asset related to federal net operating loss carry forwards of $55,689,697 and $21,165,122 at December 31, 2015 and 2014, respectively. The federal net operating loss carry forwards will begin to expire between 2034 and 2035. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carry forwards. The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured. The valuation allowance increased by $10,743,689 and $1,528,348 during 2015 and 2014, respectively.

 

The Company files income tax returns in U.S. federal, state and foreign jurisdictions and is subject to examinations by the IRS and other taxing authorities. We currently have no open audits. Tax years after December 31, 2010 remain subject to audit by the IRS. The Company has not filed its 2014 tax returns. The Company estimated federal net operating losses as of December 31, 2014 that will be available to offset future income when the tax return has been filed.

 

Authoritative guidance for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an examination. Management has reviewed the Company’s tax positions and determined there were no uncertain tax positions requiring recognition in the consolidated financial statements. The Company’s tax returns remain subject to Federal and State tax examinations for all tax years since inception as none of the statutes have expired. Generally, the applicable statutes of limitation are three to four years from their respective filings.

 

 

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the statement of operation. The Company has not recorded any interest or penalties associated with unrecognized tax benefits for any periods covered by these financial statements.

 

The Company revised certain amounts for the year ended December 31, 2014 changing its book loss. The preceding tables reflect the revisions described in Note 4.

 

The Company has not identified any uncertain tax positions requiring a reserve as of December 31, 2015 or 2014.

 

17. Earnings per Share

 

The calculation of diluted earnings per share does not include the potential dilutive impact of the 4,106,500 offering warrants outstanding during the periods presented since in 2015 and 2014 they were anti-dilutive. The calculation of diluted earnings per share does not include the potential dilutive impact of the Unit Purchase Option as it would be anti-dilutive and is not exercisable based on the Company’s average share and warrant prices.

 

The calculation of diluted earnings per share does not include the potential dilutive impact of the 6,600,000 Insider Warrants in 2015 and 2014 as they were anti-dilutive.

 

The calculation of diluted earnings per share does not include the impact of the 1,300,000 financing warrants as they were anti-dilutive in 2015 and 2014.

 

The calculation of diluted earnings per share does not include the impact of the 310,000 board of directors’ stock options as they were anti-dilutive in 2015 and 2014.

 

The following table sets forth the computation of the basic and diluted earnings per share for the years ended December 31, 2015 and 2014:

 

		Year Ended
		December 31,				December 31,
		2015				2014
Numerator for basic and diluted earnings per share:
Net (loss) income		$	(31,656,273	)		$	(4,816,548	)
Denominator:
Denominator for basic earnings per ordinary shares – weighted average shares outstanding			5,020,303				5,020,303
Effect of dilutive warrants			-				-
Denominator for diluted earnings per ordinary share – weighted average shares outstanding			5,020,303				5,020,303
Basic earnings per ordinary share		$	(6.31	)		$	(0.98	)
Diluted earnings per ordinary share		$	(6.31	)		$	(0.98	)

 

18. Significant Concentrations

 

Major customers. For the year ended December 31, 2015, sales, through Operating, to Occidental Energy Marketing, Inc. and Sunoco Partners accounted for approximately 33% and 57% of the Company’s total sales, respectively. For the year ended December 31, 2014, sales, through Petroleum, to Occidental Energy Marketing, Inc. and Sunoco Partners accounted for approximately 31% and 58% of the Company’s total sales, respectively.   No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2015 and 2014. Substantially all of the Company’s accounts receivable result from sales of oil and natural gas.

 

This concentration of customers may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative oil and natural gas purchasers in the Company’s producing region.

 

 

19. Commitments and Contingencies

 

Employment agreement.  On December 24, 2013, Arabella entered into an employment agreement with Jason Hoisager pursuant to which Mr. Hoisager agreed to act as the Chief Executive Officer and President.  The employment agreement has a term of one year and will automatically renew for additional one year terms after the end of the initial term if the agreement is not terminated at least 90 days prior to the end of the applicable term.  The employment agreement provides for a base salary of $300,000 a year, with a bonus determined by the board of directors.  If the board of directors terminates the agreement without cause, Mr. Hoisager terminates the employment agreement for good reason, or Mr. Hoisager’s employment is terminated within six months after a change of control, Mr. Hoisager will be entitled to severance equal to 24 months of his base salary and an amount equal to his bonus for the prior year.

 

Lease obligations. Petroleum had the operating lease for the Company’s office space in Midland, Texas, and beginning in January 2014, the Company paid the rent for the office lease. In January 2015 the Company leased new office space in Fort Worth, Texas and released the Midland, Texas office lease in February 2015. As of January 1, 2016 the Company sold office equipment to a third party management company. This management company has assumed responsibility for the utilities, leases and other expenses of the Fort Worth office. The third party management company is leasing the space and equipment back to the Company under a yearlong lease with renewals at $12,500 per month.

 

Drilling contracts. As of December 31, 2015 Arabella Operating did not have any drill rigs under contract.

 

Litigation. The Company has been named as a defendant in an action brought by Morris Weiss, Chapter 11 Trustee for Arabella Petroleum, LLC (“APC”), a predecessor in interest to much of the acreage that its wholly owned subsidiary, Arabella, LLC, owns and which another wholly owned subsidiary, Arabella Operating, LLC, operates. Both subsidiaries are also named defendants, as is Platinum Long Term Growth VIII, LLC (“Platinum”), the Company’s senior secured lender. Platinum’s parent fund, one of the Company’s directors, Jason Hoisager, and a company owned by Mr. Hoisager are also named defendants. The action alleges, among other things against parties other than the Company or its wholly owned subsidiaries, that the transfer of the majority of acreage owned by Arabella, LLC was constructively or actually fraudulent on the creditors of APC, are preferential transfers and that APC has, and should be allowed to foreclose on, a lien against those property interests. The APC Trustee seeks return of the properties to APC or the payment of the fair market value of those assets at the time of the transfer. The Trustee has not stated an amount of damages in dollars. The answer date to the action has been set for April 29, 2016. The Company intends to vigorously defend itself and dispute both the factual and legal basis underpinning the suit. This action was only recently filed on February 29, 2016; little to no discovery has been undertaken and no substantive rulings been made.

 

The Company is party to various legal proceedings from time to time arising in the ordinary course of business. The Company believes, other than the foregoing, all such matters are without merit or involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows.

 

20. Supplemental Oil and Gas Reserve Information (Unaudited)

 

The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers.  Such estimates are in accordance with guidelines established by the SEC and the FASB.  All of our reserves are located in the United States.  For information about our results of operations from oil and gas activities, see the accompanying consolidated statements of operations.

 

The Company emphasizes that reserve estimates are inherently imprecise.  Accordingly, the estimates are expected to change as more current information becomes available.  In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

 

 

The following table sets forth estimated proved reserves together with the changes therein (Oil and NGL in Bbls, gas in Mcf, gas converted to BOE by dividing Mcf by six) for the years ended December 31, 2015 and 2014:

 

		Oil				Gas				BOE
Balance at December 31, 2013			1,540,402				3,197,321				2,073,289
Purchase and discoveries of minerals in place			1,006,733				4,643,774				1,780,695
Production			(37,191	)			(36,258	)			(43,234	)
Balance at December 31, 2014			2,509,944				7,804,837				3,810,750
Impairment of oil and gas properties			(1,719,234	)			(6,243,066	)			(2,759,745	)
Purchase and discoveries of minerals in place			20,169				41,819				27,139
Production			(25,408	)			(31,746	)			(30,699	)
Balance at December 31, 2015			785,471				1,571,844				1,047,445

 

The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2015, and 2014, was as follows (In thousands):

 

		2015				2014
Future cash inflows		$	38,479			$	244,585
Future costs:
Production			(12,592	)			(54,325	)
Development			(11,850	)			(57,282	)
Future net cash inflows			14,037				132,978
10% discount factor			(10,340	)			(82,655	)
Standardized measure of discounted net cash flows		$	3,697			$	50,323

 

Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the year ended December 31, 2015, was as follows (In thousands):

 

		2015				2014
Standardized measure at beginning of period		$	50,323			$	32,792
Sales, net of production costs			(712	)			(1,622	)
Purchases and discoveries of minerals in place and impairments			(45,914	)			19,153
Standardized measure at end of period		$	3,697			$	50,323

 

The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period.  The average prices used for each commodity for the year ended December 31, 2015 and 2014 was as follows:

 

		Average Price
		Oil				Gas
December 31, 2014		$	85.54			$	5.51
December 31, 2015		$	50.16			$	2.64

 

Average prices for December 31, 2015 and 2014 were based on the 12-month un-weighted arithmetic average of the first-day-of-the-month price for the period from January through December during each respective calendar year.

 

 

Analysis of Reserves

 

The following table presents the Company’s estimated net proved oil and natural gas reserves and the present value of the Company’s reserves as of December 31, 2015 and December 31, 2014, based on the reserve report prepared by WDVG and WPC, respectively, and such reserve reports have been prepared in accordance with the rules and regulations of the SEC. All of the Company’s proved reserves included in the reserve reports are located in North America.

 

		December 31, 2015 (1)				December 31, 2014 (1)
Estimated proved developed reserves:
Oil (MBbls)			150.9				460.8
Natural gas (MMcf)			298.6				1,652.1
Natural gas liquids (MBbls)			-				-
Total (MBOE)			200.7				736.8
Estimated proved undeveloped reserves:
Oil (MBbls)			634.6				2,049.1
Natural gas (MMcf)			1,273.2				6,148.7
Natural gas liquids (MBbls)			-				-
Total (MBOE)			846.8				3,073.9
Estimated net proved reserves:
Oil (MBbls)			785.5				2,509.9
Natural gas (MMcf)			1,571.8				7,804.8
Natural gas liquids (MBbls)			-				-
Total (MBOE)			1,047.4				3,810.7
Percent proved developed			19.2	%			19.3	%
Probable reserves
Oil (MBbls)			-				-
Natural gas (MMcf)			-				-
Natural gas liquids (MBbls)			-				-
Total (MBOE)			-				-
Possible reserves
Oil (MBbls)			-				1,194.6
Natural gas (MMcf)			-				2,448.9
Natural gas liquids (MBbls)			-				-
Total (MBOE)			-				1,602.7

 

⁽¹⁾ Estimates of reserves as of December 31, 2015 and 2014 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2015 and 2014, respectively, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent the Company’s net revenue interest in the Company’s properties. Although Arabella believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

 

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. The Company has not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

 

 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

 

There are not and have not been any disagreements between us and our accountants on any matter of accounting principles, practices or financial statement disclosure.

 

ITEM 9A. CONTROLS AND PROCEDURES

 

An evaluation of the effectiveness of our disclosure controls and procedures as of December 31, 2015 was made under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.

 

Disclosure controls and procedures are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

 

Management’s Report on Internal Control over Financial Reporting

 

Our internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by our board of directors to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external reporting purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that in reasonable detail accurately reflect the transactions and dispositions of our assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with the authorization of our board of directors and management; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

 

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation under the criteria established in Internal Control – Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2015.

 

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(d) of the Exchange Act) that occurred during the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting 

 

ITEM 9B. OTHER INFORMATION

 

Material Impairments

 

Impairment of oil and gas assets for the year ended December 31, 2015 was $21,202,608 which is material. The impairment was due to the prolonged decline in the price of oil and gas which changed the recovery economics and expected future revenue of our producing wells and forced us to incur an impairment charge. In addition, a number of our properties were lost to lease expiration in 2015.

 

 

PART III – FINANCIAL INFORMATION

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

The directors and executive officers of the Company and their ages as of April 13, 2016, are as follows:

 

Name		Age		Title
Jason Hoisager		36		Chief Executive Officer, President and Director
Terry E. Sanford		61		Chief Financial Officer
William B. Heyn		44		Director
Berke Bakay		37		Director
Richard J. Hauser		54		Director

 

Jason Hoisager has been our Chief Executive Officer, President and a member of our board of directors since December 24, 2013. Mr. Hoisager was the founder and President of Arabella LLC, a company he established in 2008. Mr. Hoisager is also the founder and President of Arabella Petroleum Company, LLC, which currently is the operator for our properties. He is responsible for asset acquisition, business planning and the overall management of a growing operating company. Prior to Arabella LLC, Mr. Hoisager served as an independent landman and was instrumental in planning strategic land purchases, identifying investment partners, acquiring leases and marketing to operators seeking entry into the resource plays of North and West Texas. He began his career in 2005 as an independent landman acquiring leases, maintaining ownership reports and managing a land crew in Reeves County. Mr. Hoisager attended Texas Tech University where he studied Finance and Accounting and discovered his interest in the oil and gas industry. Mr. Hoisager is well qualified to serve as a director of the combined company due to his extensive experience in oil and gas and in acquiring, developing and operating properties, especially in the Southern Delaware Basin.

 

Terry E. Sanford has been our Chief Financial Officer since December 24, 2013. Mr. Sanford has been the Chief Financial Officer of Arabella LLC since November 2013. Mr. Sanford manages the Accounting, Finance and Investor Relations departments and roles for Arabella LLC. Mr. Sanford is a CPA and has a bachelor’s degree in Accounting from Sam Houston State University and a MBA in Finance from the University of Houston. Mr. Sanford is currently on the Board of Directors of the Houston, Texas Chapter of Financial Executives International and previously served as the President of the Chapter. Mr. Sanford has served as the Controller, Chief Accounting Officer, Treasurer and Chief Financial Officer in various industries including manufacturing, construction, consumer products, financial services and real estate. Prior to joining Arabella, in 2013, Mr. Sanford was the Chief Financial Officer for Automation Technology, Inc. a privately owned company that manufactures actuators for valves on oil and gas pipelines. Mr. Sanford worked for Carriage Services, Inc. (NYSE: CSV) from 1997 to 2012 where he had substantial experience in public company financial reporting, investor relations and mergers and acquisitions. Mr. Sanford’s last position at Carriage Services, Inc. was Executive Vice President, Chief Financial Officer and Chief Accounting Officer. Prior to Carriage Services, Inc., Mr. Sanford was the Chief Financial Officer for Enduro Systems, Inc. from 1996 to 1997, a company that manufactured oil and gas refinery products nationally and internationally. Mr. Sanford worked for Petrolon, Inc., an oil lubricants company, from 1992 to 1995 as the Corporate Controller. Mr. Sanford also worked in public accounting from 1982 to 1992, including PricewaterhouseCoopers, in the audit department where he served various companies in the oil and gas industries, including Exploration and Production and Drilling Companies. Prior to his public accounting tenure, Mr. Sanford was the Treasurer for Farr Oil Tool, a privately owned company that manufactured oil and gas completion equipment.

 

William B. Heyn has been a member of our Board of Directors since December 24, 2013. He had been a member of our advisory committee from our inception through December 24, 2013. Since 2007, Mr. Heyn has been Chief Executive Officer of Tritaurian Capital, Incorporated, a FINRA registered broker-dealer. From 2001 to the present, Mr. Heyn has been a Managing Director with Tritaurian Capital, Incorporated, and its predecessor companies. Tritaurian Capital serves small and middle market companies with investment banking, specialty financing and mergers and acquisitions advisory. Additionally, Mr. Heyn is a Managing Partner of Tritaurian Resources, Incorporated an international commodities broker and advisory firm. From 2004 to the present, Mr. Heyn has been a partner in E. J. McKay & Co., Inc., an international investment bank based in Shanghai. Prior to 2001, Mr. Heyn held various investment banking positions in the financial industry including in the Investment Banking Division of Merrill Lynch, the Mergers and Acquisitions Group of J. P. Morgan and the Corporate Finance Department of Morgan Stanley. Mr. Heyn was an advisor to CS China Acquisition Corp., a Specified Purpose Acquisition Corporation that subsequently merged with a target in China to form Iao Kun Group Holdings Company Limited (previously known as Asia Entertainment & Resources Ltd.), which is listed on the NASDAQ Stock Market (NASDAQ: IKGH). Mr. Heyn was an advisor to China Unistone Acquisition Corp., a Specified Purpose Acquisition Corporation that subsequently merged with a target in China to form Yucheng Technologies Limited, which is listed on the Nasdaq Capital Market (NASDAQ: YTEC). Mr. Heyn received a B.A. from Yale University with majors in history and political science and currently holds Series 7, 24, 63, 79 and 99 securities licenses. Mr. Heyn is well qualified to serve as our director as a result of his experience in capital markets, mergers and acquisitions and public company corporate governance and management.

 

 

Berke Bakay has been a member of our board of directors since inception. From inception until the close of the business combination, Mr. Bakay was the Executive Chairman of our board. Mr. Bakay has been the President and Chief Executive Officer of Kona Grill, Inc. (NASDAQ: KONA), an American grill and sushi bar (“Kona”) since January 2012. He has also serves on the board of directors of Kona. Mr. Bakay founded BBS Capital Management, LP, a Texas limited partnership that serves as the investment manager to the BBS Capital Fund, LP, in January 2008 and has served as its managing member since its formation. Prior to forming BBS Capital Management, LP, Mr. Bakay was the co-founder and co-portfolio manager of Patara Capital, L.P., an investment management firm based in Dallas, Texas from January 2006 through December 2007. From May 2005 through January 2006, Mr. Bakay was an equity analyst at Southwest Securities, Inc., a subsidiary of SWS Group, Inc. (NYSE: SWS), a financial services company, where he covered the specialty retail industry. Mr. Bakay currently serves on the board of directors of Kona Grill, Inc. (NASDAQ: KONA), an American grill and sushi bar. Mr. Bakay graduated from Boston College, Carroll School of Management with a Bachelor of Science in finance and from Boston College, Carroll School of Management with a Master of Science in Finance. Mr. Bakay is well qualified to serve as our director as a result of his experience with public companies as well as his expertise in the capital markets.

 

Richard J. Hauser has been a member of our Board of Directors since December 24, 2013. He had been a member of our advisory committee from our inception through December 24, 2013. Mr. Hauser has served as a director of Kona Grill, Inc. (NASDAQ: KONA) since December 2004. Mr. Hauser serves as the President and owner of Capital Real Estate, Inc., a commercial real estate development company based in Minneapolis, Minnesota, which he founded in 2001. In addition, Mr. Hauser is the Manager and owner of Net Lease Development, LLC, which is a controlled operating company under Capital Real Estate, Inc., as well as a member and managing partner of several other partnerships formed for real estate and related ventures. Prior to founding Capital Real Estate, Inc. and Net Lease Development, LLC, Mr. Hauser served as a partner with Reliance Development Company, LLC from 1992 to 2001, where he was responsible for the management, development, and sale of retail properties. Mr. Hauser has a strong executive background in commercial real estate and finance, with extensive experience in business operations and strategic planning. Mr. Hauser has an undergraduate degree in Business and Liberal Arts from the University of Minnesota and a graduate degree in Real Estate and Finance from the University of Denver. Mr. Hauser is well qualified to serve as our director as a result of his experience in business management and development.

 

Family relationships

 

There are no family relationships among the Company’s executive officers, directors and significant employees. As of December 31, 2015, the Company personnel do not have any involvement in legal proceedings requiring disclosure pursuant to the Rules and Regulations of the SEC.

 

Board Independence and Committees

 

Our Board of Directors has determined that Messrs. Richard Hauser and Berke Bakay qualify as independent directors under the rules of the Nasdaq Stock Market because they are not currently employed by us, and do not fall into any of the enumerated categories of people who cannot be considered independent in the Nasdaq Stock Market Rules.

 

Our board of directors has established an audit committee, a compensation committee and a nominating committee.

 

Audit Committee. The audit committee currently consists of Richard Hauser, Berke Bakay and William B. Heyn. The board of directors believes that each of Messrs. Hauser, Bakay and Heyn qualifies as an “audit committee financial expert”, as such term is defined in the rules of the Securities and Exchange Commission. The board of directors intends to adopt an audit committee charter in the near future.

 

Compensation Committee. The compensation committee consists of Richard Hauser, Berke Bakay and William B. Heyn. Messrs. Hauser and Bakay do not have any direct or indirect material relationship with us other than as a director. Our board of directors intends to adopt a compensation committee charter in the near future.

 

Nominating Committee. The nominating and corporate governance committee consists of Richard Hauser, Berke Bakay and William B. Heyn. Messrs. Hauser and Bakay do not have any direct or indirect material relationship with us other than as a director. Our board of directors intends to adopt a nominating committee charter in the near future

 

 

In making nominations, the nominating and corporate governance committee is required to submit candidates who have the highest personal and professional integrity, who have demonstrated exceptional ability and judgment and who shall be most effective, in conjunction with the other nominees to the board, in collectively serving the long-term interests of the shareholders. In evaluating nominees, the nominating and corporate governance committee is required to take into consideration the following attributes, which are desirable for a member of the board: leadership, independence, interpersonal skills, financial acumen, business experiences, industry knowledge, and diversity of viewpoints.

 

Compliance with Section 16(a) of the Exchange Act

 

Section 16(a) of the Securities Exchange Act of 1934 requires our directors and executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC initial reports of ownership and reports of change in ownership of common stock and other of our equity securities. Officers, directors and greater than ten percent stockholders are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. Except for each of our officers and directors not timely filing a Form 3 when we became a U.S. reporting company and each of independent directors not timely filing a Form 4 relating to a grant of options, to our knowledge, no persons have failed to file, on a timely basis, the reports required by Section 16(a) of the Exchange Act during the most recent fiscal year ended December 31, 2015.

 

Code of Ethics and Corporate Policy

 

The board of directors intends to adopt a Company Code of Ethics and other Corporate Policies in the near future.

 

Officer and Director Qualifications

 

Our officers and board of directors are composed of a diverse group of leaders. Many of the current officers or directors have senior leadership experience in both public and private companies. In these positions, they have also gained experience in core management skills, such as strategic and financial planning, public company financial reporting, compliance, risk management, and leadership development. Most of our officers and directors also have experience serving on boards of directors and board committees of other public companies and private companies, and have an understanding of corporate governance practices and trends, which provides an understanding of different business processes, challenges, and strategies. Further, our officers and directors also have other experience that makes them valuable, such as prior experience with blank check companies, managing and investing assets or facilitating the consummation of business combinations.

 

ITEM 11. EXECUTIVE COMPENSATION

 

The following table (the “Summary Compensation Table”) sets forth all compensation awarded to, earned by or paid to our principal executive officer and our other most highly compensated executive officer other than our principal executive officer who were serving as executive officers as of December 31, 2015 (collectively, the “Named Executive Officers”). No other executive officers received compensation in excess of $100,000 in 2015. Other than as described in this report, we do not have any supplemental executive retirement plans, change in control agreements or company perks (e.g., company cars, country club memberships, etc.).

 

Summary Compensation Table

 

Name and Principal Position		Period Ending		Salary				Bonus				Stock Awards				Option- Based Awards				Other				Total
Jason Hoisager		December 31, 2015		$	311,538				--				--				--			$	27,226			$	338,765
Chief Executive Officer		December 31, 2014			300,000				--				--				--				22,299				322,299
Terry E. Sanford		December 31, 2015			48,462				--				--				--				12,733				61,195
Chief Financial Officer		December 31, 2014			280,000				--				--				--				9,455				289,455

 

 

Potential Payments Upon Termination or Change in Control

 

The following table sets forth potential payments payable to our named executive officers upon a termination of employment without cause or resignation for good reason or termination of employment without cause or resignation for good reason following a change in control. The table below reflects amounts payable to our executive officers assuming their employment was terminated on December 31, 2015 and, if applicable, a change in control also occurred on such date.

 

		Upon Termination Without Cause, Resignation for Good Reason, or Termination within Six Months of a Change in Control
Name		Cash Severance(1)				Total
Jason Hoisager		$	600,000			$	600,000

 

(1)	In addition to 24 months of his base salary, Mr. Hoisager would be entitled to an amount equal to his bonus for the prior year, if any.

 

Overview of Our Fiscal 2015 Executive Compensation

 

Elements of Compensation

 

Our executive compensation program consisted of the following components of compensation in 2014:

 

Base Salary. Each named executive officer receives a base salary for the expertise, skills, knowledge and experience they offer to our management team. Base salaries are periodically adjusted to reflect:

 

	●	The nature, responsibilities, and duties of the officer’s position;
	●	The officer’s expertise, demonstrated leadership ability, and prior performance;
	●	The officer’s salary history and total compensation, including annual cash incentive awards and annual equity incentive awards; and
	●	The competitiveness of the officer’s base salary.

 

Each named executive officer’s base salary for fiscal 2015 is listed in the 2015 Summary Compensation Table.

 

Equity Incentive Awards.

 

None.

 

Other Benefits.

 

We provide one or more of the named executive officers with an annual automobile allowance, as set forth in more detail in the fiscal 2015 Summary Compensation Table.

 

The amounts paid to the named executive officers in 2015 in respect of these benefits are reflected above in the fiscal 2015 Summary Compensation Table under the “All Other Compensation” column.

 

Employment Agreements

 

On December 24, 2013, we entered into an employment agreement with Jason Hoisager pursuant to which Mr. Hoisager agreed to act as our Chief Executive Officer and President. The employment agreement has a term of one year and will automatically renew for additional one-year terms after the end of the initial term if the agreement is not terminated at least 90 days prior to the end of the applicable term. The employment agreement provides for a base salary of $300,000 a year, with bonus determined by our board of directors. If the board of directors terminates the agreement without cause, Mr. Hoisager terminates the employment agreement for good reason, or Mr. Hoisager’s employment is terminated within six months after a change in control, Mr. Hoisager will be entitled to severance equal to 24 months of his base salary and an amount equal to his bonus for the prior year.

 

 

Outstanding Equity Incentive Awards at Fiscal Year-End

 

There are no outstanding equity awards held by our named executive officers as of December 31, 2015.

 

Option Exercises and Stock Vested

 

No officers or directors exercised warrants and no stock vested during fiscal 2015.

 

Compensation Committee Interlocks and Insider Participation

 

None of our officers currently serves, or has served during the last completed fiscal year, on the compensation committee or board of directors of any other entity that has one or more officers serving as a member of our board of directors.

 

Director Compensation

 

The following table sets forth certain information concerning compensation paid or accrued to our non-executive directors during the year ended December 31, 2015.

 

Name		Fees Earned or Paid in Cash				Stock Awards				Option Awards(1)				Non-Equity Incentive Plan Compensation				Change in Pension Value and Nonqualified Deferred Compensation Earnings				All Other Compensation				Total
Berke Bakay		$	45,000				-			$	24,924				-				-				-			$	69,924
Richard Hauser			45,000				-				24,924				-				-				-				69,924
William B. Heyn			47,000				-				24,924				-				-				-				71,924

 

(1)

On May 5, 2014 we granted each non-employee director 30,000 stock options to purchase its ordinary shares for joining the board and 20,000 stock options to purchase its ordinary shares for each year of service commencing from January 30, 2014. The stock options vest ratably over two years and expire five years from the grant date. The stock options have an exercise price of $6.15 per share, which represents the closing price of our ordinary shares the day prior to the grant. The aggregate grant date fair value of the options granted was determined to be approximately $558,950 using the Black-Scholes pricing model. Significant assumptions used in the valuation include an expected term of 3.5 years utilizing the “Simplified Method” as we do not have sufficient historical experience to estimate an expected term, an expected volatility of 49.0% based on historical value and corresponding volatility of our peer group stock price for a period consistent with the stock option expected term, a risk free interest rate of 0.9% based on the a U.S. Treasury Note with a similar term to the expected term on the date of the grant, and an expected dividend yield of 0.0% as we do not expect to pay dividends in the near future. According to the terms of the option plan, vesting was retroactive to the beginning of service in January 2014.

(2)

On February 2, 2015 we granted each non-employee director 20,000 stock options to purchase its ordinary shares for the year of service commencing from January 30, 2015. All 20,000 stock options vest ratably over two years on a quarterly basis and expire five years from the grant date. The stock options have an exercise price of $3.35 per share, which represents the closing price of our ordinary shares the day prior to the grant date. The grant date fair value of the options granted was determined to be $74,772 using the Black-Scholes pricing model. Significant assumptions used in the valuation include an expected term of 3.5 years utilizing the “Simplified Method” as we do not have sufficient historical experience to estimate an expected term, an expected volatility of 51.0% based on historical value and corresponding volatility of our peer group stock price for a period consistent with the stock option expected term, a risk free interest rate of 0.8% based on the a U.S. Treasury Note with a similar term to the expected term on the date of the grant, and an expected dividend yield of 0.0% as we do not expect to pay dividends in the near future.

 

All of our directors presently receive annual compensation of $30,000 in cash and 20,000 options to purchase our ordinary shares at an exercise price to be set on January 30^th of each fiscal year. The directors of the Company are entitled to receive an initial grant of 30,000 options to purchase our ordinary shares upon joining the board. Since each of our directors joined our board in 2014, each received a total of 50,000 options for fiscal 2014 at an exercise price of $6.15, the closing price of our ordinary shares on May 4, 2014, the last close prior to the options being granted. Each director received 20,000 options for fiscal 2015 at the exercise price of $3.35 the last close prior to the options being granted. The chairman of the audit committee receives additional annual cash compensation of $10,000 per year and the other members of the audit committee each receive additional annual cash compensation of $5,000 per year. The chairmen of the compensation and nominating committees each receive additional annual cash compensation of $5,000 per year and the other members of these committees each receive additional annual cash compensation of $3,000. Each director receives $1,500 for each board meeting and $1,000 for committee meeting that he or she attends in person and $500 for each board or committee meeting he or she attends telephonically. Additionally our board members are reimbursed for all travel and other costs associated with their service on our board.

 

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

The following table sets forth, as at April 13, 2016, certain information with respect to the beneficial ownership of the Company's common stock by each person known by us to be the beneficial owner of more than five percent (5%) of the Company's common stock; by each of the Company's directors and named executive officers; and by all executive officers and directors as a group.

 

Beneficial ownership includes voting or investment power with respect to the securities and takes into consideration options or warrants exercisable by a person within 60 days after the date of this report. Except as indicated below, and subject to applicable community property laws, the persons named in the table have sole voting and investment power with respect to all securities shown as beneficially owned by them.

 

Name and Address (1)		Number of Shares Beneficially Owned				Percentage of Ownership (2)
Directors and executive officers:
Berke Bakay(3)			3,347,355				41.8
Jason Hoisager			1,659,489				33.1
Terry E. Sanford			-				-
Richard J. Hauser(4)			3,338,428				41.7
William B. Heyn(5)			327,664				6.2
All directors and executive officers as a group (5 individuals)			8,672,936				77.2
Principal shareholders:
BBS Capital Fund, LP(3)			3,278,428				41.2
Hauser Holdings LLC(4)			3,278,428				41.2
Greg McCabe			1,003,597				20.0
Platinum Long Term Growth VIII, LLC(6)			1,150,000				18.6
Legion Partners Holdings, LLC(7)			700,434				12.2
AQR Capital Management, LLC(8)			384,960				7.1
John V. Calce(9)			267,662				5.2
James R. Preissler(10)			267,662				5.2

 

(1)	Unless otherwise noted, the business address for each of our beneficial owners is 509 Pecan Street, Suite 200, Fort Worth, Texas 76102.

 

(2)

Based on 5,020,303 ordinary shares outstanding as of December 31, 2015, excluding treasury shares. Warrants are deemed to be outstanding for the purpose of computing the percentage ownership of the indicated individual or group, but are not deemed to be outstanding for the purpose of computing the percentage ownership of any other person shown in the table.

 

(3)

The number of ordinary shares beneficially owned by Mr. Bakay consists of (i) 345,928 ordinary shares beneficially owned by BBS Capital Fund, LP, (ii) 8,927 ordinary shares owned by Mr. Bakay, (iii) 60,000 options to purchase ordinary shares owned by Mr. Bakay and (iv) warrants exercisable for 2,932,500 ordinary shares, all of which are owned by BBS Capital Fund, LP. Mr. Bakay and BBS Capital Fund, LP have sole voting and dispositive power over all such securities. The address of BBS Management Group is 5524 E. Estrid Avenue, Scottsdale, Arizona 85254.

 

(4)

The number of ordinary shares beneficially owned by Mr. Hauser consists of (i) 345,928 ordinary shares beneficially owned by Hauser Holdings, LLC, (ii) 60,000 options to purchase ordinary shares owned by Mr. Hauser, and (iii) warrants exercisable for 2,932,500 ordinary shares, all of which are owned by Hauser Holdings, LLC. Mary Jane Hauser has sole voting and dispositive power over all securities held by Hauser Holdings LLC. The address of Hauser Holdings LLC is 50 South Sixth Street, Minneapolis, Minnesota 55402. Ms. Hauser is the wife of Richard J. Hauser, one of our directors.

 

 

(5)	The number of ordinary shares beneficially owned by Mr. Heyn consists of (i) 102,664 ordinary shares, (ii) 60,000 options to purchase ordinary shares and (iii) warrants exercisable for 165,000 ordinary shares.

 

(6)	The number of ordinary shares beneficially owned by Platinum Long Term Growth VIII, LLC consist of warrants exercisable for 1,150,000 ordinary shares. The business address of Platinum Long Term Growth VIII, LLC is 152 West 57th Street, 4th Floor, New York, New York 10019.

 

(7)

Based on a Schedule 13G filed on November 12, 2014 by Legion Partners Holdings, LLC. The number of ordinary shares beneficially owned by Legion Partners Holdings, LLC consists of warrants exercisable for 700,434 ordinary shares. Legion Partners Holdings, LLC is the sole member of Legion Partners Asset Management, LLC and managing member of Legion Partners, LLC, each of which may be deemed beneficial owners of these warrants. Legion Partners, LLC serves as the general partner of each of Legion Partners, L.P. I which owns 584,364 warrants and Legion Partners, L.P. II, which owns 115,070 warrants. Additionally each of Messrs. Christopher S. Kiper, Bradley S. Vizi and Raymond White, whom serve as managing directors of Legion Partners Asset Management, LLC and managing members of Legion Partners Holdings, LLC, may be deemed the beneficial owners of the aggregate 700,434 warrants owned by Legion Partners, L.P. I and Legion Partners, L.P. II. The principal business address of each reporting person is 9401 Wilshire Boulevard, Suite 705, Beverly Hills, California 90212.

 

(8)

Based on a Schedule 13G filed on February 7, 2014 by AQR Capital Management, LLC. The number of ordinary shares beneficially owned by AQR Capital Management, LLC consists of warrants exercisable for 384,960 ordinary shares. The address of the business office of AQR Capital Management, LLC is Two Greenwich Plaza, 3rd Floor, Greenwich, Connecticut 06830.

  

(9)	The number of ordinary shares beneficially owned by Mr. Calce consists of (i) 102,662 ordinary shares and (ii) warrants exercisable for 165,000 ordinary shares. The business address of Mr. Calce is 17950 Preston Road, Suite 1080A Dallas, Texas 75252.

 

(10)	The number of ordinary shares beneficially owned by Mr. Preissler consists of (i) 102,662 ordinary shares and (ii) warrants exercisable for 165,000 ordinary shares. The business address of Mr. Preissler is 50 Old Route 25A Fort Salonga, NY 11768.

 

As of April 13, 2016, approximately 99% of our outstanding ordinary shares are held by 18 record holders in the United States.

 

The Company is not aware of any arrangement, the operation of which may, at a subsequent date, result in a change in control of the Company. There are no provisions in the governing instruments of the Company that could delay a change in control of the Company.

 

Equity Compensation Plan Information

 

The following table provides information as of December 31, 2015 with respect to compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance:

 

Plan Category		Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)				Percentage of Outstanding Shares				Weighted-average exercise price of outstanding options, warrants and rights (b)				Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders			-				-				-				-
Equity compensation plans not approved by security holders (1)			610,000				10.8			$	5.31				-
Total			610,000				10.8			$	5.31				-

 

(1)	Reflects the 300,000 $5.00 warrants issued as compensation for out advisors in the Senior Secured Note financing and 310,000 options issued to our Board of Directors.

 

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

Certain Relationships and Related Transactions

 

Below is a list of companies that Jason Hoisager has had, or currently has, an interest in, along with a description of the relationship to that company to us:

 

Arabella Petroleum Company, LLC (APC) was the historical operator of record for properties owned by us. APC is owned by Jason Hoisager. We owed $2,952,190 and $3,382,514 for joint interest billings to APC as of December 31, 2015 and December 31, 2014, respectively. As of December 31, 2015 and December 31, 2014, respectively, APC owed us $369,776 and $814,689 in its proportionate share of revenues from oil and gas sales. During the years ended December 31, 2014 we paid APC $17,072,542 in capital costs associated with our portion of well drilling and maintenance costs incurred by APC.

 

During the year ended December 31, 2015, advances of $1,950,605 were received from affiliates of the Company’s CEO and other shareholders.

 

The Company has a month to month consulting agreement with an affiliate of one of its directors to provide certain financial and operation services for $24,584 per month.

 

We are indebted to Jason Hoisager for $3,007,170 as of December 31, 2014, which relates to oil and gas properties that Mr. Hoisager had APC transfer at cost to us. This indebtedness is evidenced by a subordinated unsecured promissory note, which note bears no interest and matures in 2023.

 

On May 1, 2014 we received a loan from Hauser Holdings, LLC an affiliate of Richard Hauser, one of our directors. The $800,000 loan was due August 31, 2014 and bore an interest rate of 10% per annum. This loan was repaid on September 4, 2014 along with $28,222 of accrued interest.

 

On June 10, 2014 we received a loan from BBS Capital Fund, LP an affiliate of Berke Bakay, one of our directors. The $500,000 loan was due August 31, 2014 and bore an interest rate of 10% per annum. This loan was repaid on September 4, 2014 along with $12,500 of accrued interest.

 

On June 26, 2014 our Chief Executive Officer Jason Hoisager has purchased 190,477 of the Company’s ordinary shares for $10.50 a share in a private subscription. The shares were newly issued shares of the company.

 

Director Independence

 

Our Board of Directors has determined that Messrs. Richard Hauser and Berke Bakay qualify as independent directors under the rules of the Nasdaq Stock Market because they are not currently employed by us, and do not fall into any of the enumerated categories of people who cannot be considered independent in the Nasdaq Stock Market Rules.

 

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

 

The following table sets forth the aggregate fees by categories specified below in connection with certain professional services rendered by Marcum LLP, our principal external independent registered public accounting firm, for the periods indicated.

 

		2015				2014
Audit fees(1)		$	139,061			$	128,184
Audit related fees(2)			24,762				28,446
Tax fees(3)			3,394				14,248
Total fees		$	167,217			$	170,878

 

(1)	“Audit fees” means the aggregate fees billed for an audit of our consolidated financial statements and our internal control over financial reporting.
(2)	“Audit related fees” means the aggregate fees billed for additional work by the auditors in conjunction with our audit and expenses incurred.
(3)	“Tax fees” means the aggregate fees billed by our auditors for work on our taxes

 

Our board of directors is to pre-approve all auditing services and permitted non- audit services to be performed for us by our independent auditor, including the fees and terms thereof (subject to the de minimums exceptions for non-audit services described in section 10A(i)(1)(B) of the Exchange Act which are approved by the audit committee or our board of directors prior to the completion of the audit).

 

 

PART IV

 

ITEM 15. EXHIBITS

 

2.1		Agreement and Plan of Merger and Reorganization dated October 23, 2013 by and among Lone Oak Acquisition Corporation, a Cayman Islands company, Arabella Exploration Corp., a Delaware corporation, Arabella Exploration, LLC, a Texas limited liability company, and each of the Stockholders set forth on Schedule I thereto.**
3.1		Amended and Restated Articles of Association*
4.1		Specimen Unit Certificate*
4.2		Specimen Ordinary Share Certificate*
4.3		Specimen Warrant Certificate*
4.4		Form of Unit Purchase Option*
4.5		Form of Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant*
4.6		Form of Representative’s Unit Purchase Option*
5.1		Opinion of Conyers Dill & Pearman*
5.2		Opinion of Loeb & Loeb LLP*
10.1		Form of Share Escrow Agreement between the Registrant, Continental Stock Transfer & Trust Company and the Initial Shareholders*
10.2		Form of Registration Rights Agreement among the Registrant and its Initial Shareholders*
10.3		Employment Agreement with Jason Hoisager, dated December 24, 2013***
10.4		Registration Rights Agreement among the Registrant and the former members of Arabella Exploration, Limited Liability Company dated December 24, 2013***
10.5		Voting agreement among the Company and the security holders named therein dated December 24, 2013***
10.6		Lock-up Agreement dated December 24, 2013***
21.1		List of Subsidiaries
23.1		Consent of W.D. Von Gonten & Co. with respect to the reserve report included as Exhibit 99.1.
31.1		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2		Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2		Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
99.1		Report of W.D. Von Gonten & Co., dated March 23, 2016, with respect to an estimate of the proved reserves, future production and income attributable to certain leasehold interests of Arabella Exploration, Inc. as of December 31, 2015.

 

*	Incorporated by reference to the Registrant’s Registration Statement on Form F-1 (Commission File No. 333-172334).
**	Incorporated by reference to the Registrant’s Report of Foreign Private Issuer on Form 6-K dated October 2013 and filed with the SEC on October 25, 2013.
***	Incorporated by reference to the Registrant’s Shell Company Report on Form 20-F dated December 24, 2013 and filed with the SEC on December 31, 2013.

 

 

SIGNATURES

 

Pursuant to the requirements of the Exchange Act, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

	ARABELLA EXPLORATION, INC.
April 14, 2016	By:	/s/ Terry E. Sanford
		Name: Terry E. Sanford
		Title: Chief Financial Officer

 

Pursuant to the requirements of the Exchange Act, this Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature		Title		Date
/s/ Jason Hoisager		Chief Executive Officer, Director		April 14, 2016
Jason Hoisager		(principal executive officer)
/s/ Terry E. Sanford		Chief Financial Officer		April 14, 2016
Terry E. Sanford		(principal accounting and financial officer)
/s/ William B. Heyn		Director		April 14, 2016
William B. Heyn		(principal accounting and financial officer)
/s/ Richard Hauser		Director		April 14, 2016
Richard Hauser
/s/ Berke Bakay		Director		April 14, 2016
Berke Bakay

 

 

54