10-K 1 f10k2014_arabellaexpl.htm ANNUAL REPORT

 

 

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, 2014

 

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, 2014: $13,657,641.

 

As of April 14, 2015, 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.

 

i
 

 

ARABELLA EXPLORATION, INC.

 

INDEX

 

    Page
PART I    
Items 1. and 2. Business and Properties  1
Item 1A. Risk Factors  23
Item 1B. Unresolved Staff Comments  35
Item 3. Legal Proceedings  35
Item 4. Mine Safety Disclosures  35
PART II    
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities  36
Item 6. Selected Financial Data  37
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations  38
Item 7A. Quantitative and Qualitative Disclosures About Market Risk  46
Item 8. Financial Statements and Supplementary Data  47
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures  48
Item 9A. Controls and Procedures  48
Item 9B. Other Information  48
PART III  
Item 10. Directors, Executive Officers and Corporate Governance 49
Item 11. Executive Compensation  51
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters  54
Item 13. Certain Relationships and Related Transactions and Director Independence  56
Item 14. Principal Accountant Fees and Services  57
PART IV    
Item 15. Exhibits  58

 

ii
 

 

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).

 

iii
 

 

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.

 

iv
 

 

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.

 

v
 

 

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.

 

vi
 

 

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 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 merger with Arabella Exploration, Limited Liability Company, 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.

 

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, 2013, we acquired approximately 9,282 additional gross acres, which brought our total gross acreage position in the Delaware Basin to 10,882 gross acres, or 5,426 net acres, at December 31, 2013. At the time of these acquisitions, none of the acquired acreage had existing production.

 

During 2014:

 

we sold gross 2,910, net 1,569, of our acres under lease – otherwise known as the Johnson 44, Weatherby, Topo Chico, Roark, Johnson 6, Johnson 20 and Cannon leases. This acreage was sold for $5,665,121 for which we recognized a gain of $3,084,917.

 

we acquired additional working interests in all of our producing wells, Locker State #1H (18.0%), Graham #1H (18.0%), Woods #1H (10.0%), Vastar State #1V (5.0%), Jackson #1H (7.1%) and Emily Bell #1H (1.5%), as well as the drilled, but yet to be completed, Woods #2H (4.5%) and the completed, but currently shut in, SM Prewitt #1H (18.0%). Additionally, we acquired an additional 18.0% of all of the remaining undrilled working interests in the SM Prewitt, Locker State and Graham leases, 16.5% of the undrilled Johnson 103 and 138 leases as well as 5.0% of all of the remaining undrilled working interests in the Woods, Vastar State, Jackson and Emily Bell leases.

 

we backed into a 1.371% working interest in 20,263 gross acres held by Brigham Resources Operating, LLC in the Delaware Basin. Our interest amounts to 270 net acres. There are currently two vertical wells and seven horizontal wells producing on this project.

 

we backed into a 0.5333% working interest in 6,166 gross acres held by Energen Resources Corporation in the Delaware Basin. Our interest amounts to 29 net acres. There are currently three horizontal wells producing on this project.

 

Taking into account the foregoing, our net acreage position in the Delaware Basin was approximately 4,972 net acres as of December 31, 2014.

 

1
 

 

AEX Operating, LLC, a wholly owned subsidiary of Arabella, is the operator of record for this acreage. As of December 31, 2014, 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, 2014, our estimated net proved oil reserves were 2,509,941 MBbls and natural gas reserves were 7,804,834 MMcf, based on a reserve report prepared by Williamson Petroleum Consultants, Inc., or WPC, independent reserve engineers. Of the proved oil reserves, approximately 18.4% are classified as proved developed producing, or PDP, and proved developed non-producing, or PDNP, the remaining 81.6% are classified as proved undeveloped, or PUD. Of the proved gas reserves, approximately 21.2% are classified as PDP and PDNP and the remaining 78.8% are classified as PUD. PUD reserves included in this estimate are from seventeen gross horizontal well locations. As of December 31, 2014, these proved reserves were approximately 65.9% oil and 34.1% natural gas.

 

Additionally, we had 0 MBbls, of probable and 1,194,561MBbls of possible oil reserves as well as 0 MMcf of probable and 2,448,849 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. We had a 14.6% working interest in this well. 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, 2014, 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 have not completed that lateral. In 2014 we acquired additional working interests in this well, bringing our total working interest to 36.6%. The SM Prewitt #1H is currently shut-in.

 

Our second horizontal well was the Locker State #1H, in which we had a 14.6% working interest, 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, 2014, the Locker State #1H had produced a total of 23.5 MBbls of oil and 64.7 MMcf of natural gas. In 2014 we acquired additional working interests in this well, bringing our total working interest to 36.6%.

 

Our third horizontal well was the Graham #1H, in which we had a 15.6% working interest, 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, 2014, the Graham #1H had produced a total of 50.9 MBbls of oil and 144.2 MMcf of natural gas. In 2014 we acquired additional working interests in this well, bringing our total working interest to 37.6%.

 

Our fourth horizontal well was the Woods #1H, in which we had a 23.3% working interest, 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, 2014, the Woods #1H had produced a total of 77.6 MBbls of oil and 94.0 MMcf of natural gas. In 2014 we acquired additional working interests in this well, bringing our total working interest to 33.2%.

 

We drilled one vertical well, the Vastar State #1V, in which we had a 57.1% working interest, which was completed in December 2013. Through December 31, 2014, the Vastar State #1V had produced a total of 5.4 MBbls of oil and 7.9 MMcf of natural gas. In 2014 we acquired additional working interests in this well, bringing our total working interest to 66.1%.

 

Our fifth horizontal well was the Jackson #1H, in which we had a 53.0% working interest, 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, 2014, the Jackson #1H had produced a total of 29.2 MBbls of oil and 50.7 MMcf of natural gas. In 2014 we acquired additional working interests in this well, bringing our total working interest to 67.3%.

 

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Our sixth horizontal well was the Emily Bell #1H, in which we have a 54.0% working interest, 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, 2014, the Emily Bell #1H had produced a total of 29.5 MBbls of oil and 55.4 MMcf of natural gas. In 2014 we acquired additional working interests in this well, bringing our total working interest to 58.4%.

 

Our seventh horizontal well was the Woods #2H, in which we had a 28.5% working interest, which has been drilled and is awaiting completion. We performed a data frac on this well and through December 31, 2014 it had produced oil and gas while awaiting final completion. In 2014 we acquired additional working interests in this well, bringing our total working interest to 38.1%.

 

Based on the Williamson Reserve Report from current production, EURs for each of the horizontal wells will be in the range of 100 to 600 MBOE. The table below summarizes our current working interest and each well’s performance.

 

Well  Working
Interest
   Lateral
Length
(ft)
   Completed Formation  Peak Rate
24-hour
(BOE/d)
   Peak Rate
30-day
(BOE/d)
   Percent
Oil
(%)
   EUR
(BOE)
 
SM Prewitt #1H   36.5500    4,200   Wolfcamp C   283    146    89    100,000 
Locker State #1H   36.5500    4,200   Wolfcamp D   350    109    85    186,000 
Graham #1H   37.5500    4,200   Wolfcamp D   634    383    83    250,000 
Woods #1H   33.1563    4,200   Wolfcamp B   1,221    634    82    600,000 
Vastar State #1V   66.1375    Vertical   Wolfcamp A-D   TBD    TBD    TBD    TBD 
Jackson #1H   67.2647    4,200   Wolfcamp B   875    402    82    530,000 
Emily Bell #1H   58.3750    4,200   Wolfcamp A   1,125    482    85    TBD 
Woods #2H   38.1438    4,200   Wolfcamp B   TBD    TBD    TBD    TBD 

 

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

 

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 its 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 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. We are currently not engaged in any drilling activity due to the reduced price of oil. Our current cash position, availability of financing from our Senior Secured Note facility and current level of operating cash flows may not, in aggregate, be 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 intend to actively drill and 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. As of December 31, 2014, we have identified 360 - 600 potential horizontal drilling locations on our acreage in the Delaware Basin based on an industry standard 160-acre spacing.

 

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Examine intervals in addition to the Wolfcamp. Our initial horizontal focus has been on the Wolfcamp A, B, C and D intervals in Reeves and Ward Counties. We believe that many, if not all, of our prospects contain additional stacked pays in the Avalon Shale, Bone Spring Sands and other formations. By exploiting the reserves and production in these additional formations we can potentially apply a multiplying effect to our reserves and recoverable oil and gas.

 

Optimize hydrocarbon recovery through horizontal drilling of multiple intervals. Assuming the price of oil supports sufficient returns, we believe there are opportunities to target multiple intervals in the Wolfbone play with horizontal wells. Our initial horizontal focus has been on the Wolfcamp A, B, C and D intervals in Reeves and Ward Counties. Our first seven horizontal wells were completed in 2012, 2013 and 2014 and had lateral lengths of approximately 4,200 feet. We expect that the “stacked” lateral wells will result in higher per well recoveries and lower development costs per BOE as compared to drilling a single horizontal well per vertical wellbore. We did drill a dual lateral horizontal, which involved reentering a well with the original lateral in the Wolfcamp C, and then adding an additional lateral in the Wolfcamp A above it, with the goal of comingling production. While the second lateral was successfully drilled, it has not been completed.

 

Optimize future recovery with potentially increased well density. We closely monitor industry trends with respect to higher well density, which could increase the recovery factor per section and enhance returns since infrastructure is typically in place. Currently our acreage is set for drilling on 160 acre spacing but we anticipate that there may be downspacing opportunities in the future allowing increased well density across our acreage.

 

Leverage our experience operating in the Southern Delaware Basin. Our executive team, which has significant experience in the Southern Delaware Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling, completion and production techniques. Our focus on efficient drilling and completion techniques, and the reduction in time to market with our product, is an important part of the drilling program we have planned for potential drilling locations. In addition, we believe that the experience of our executive team in deviated and horizontal drilling and completions should help reduce the execution risk normally associated with these complex well structures. Additionally, our completion techniques are continually evolving as we evaluate hydraulic fracturing practices that may potentially increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.

 

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. We intend to continue to pursue acquisitions that 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.

 

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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. In addition, our executive team has significant experience with both drilling and completing horizontal wells as well as horizontal well reservoir and geologic expertise, which will be of strategic importance as we expand our horizontal drilling activity.
    
  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. 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 86% oil and 14% natural gas for 2014. We believe that our historical horizontal development success will be complemented with our “stacked” horizontal drilling locations that could ultimately translate into an increased recovery factor on a per section basis.
    
  Multi-year drilling inventory. We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities, provided a sufficient price for oil. As of December 31, 2014, based on our initial results and those of other operators in the area to date, combined with our interpretation of various geologic and engineering data, we have identified 360 – 600 potential horizontal locations on our acreage. Of the potential 360 – 600 horizontal locations, seventeen of them are horizontal PUD's. These locations exist across most of our acreage blocks and in multiple horizons. Of the 360 – 600 potential horizontal locations, 60 are in each of the Wolfcamp A, B, C and D horizons and the remainder in the various Bone Spring horizons. We have not assigned any horizontal locations to the Delaware interval but believe that it may also have development potential. Our current horizontal location count is based on 1,320 foot spacing between wells. The ultimate inter-well spacing may be closer than 1,320 feet, which would result in a higher location count.
    
  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.
    
  High degree of operational control. We are the operator of all of our Permian Basin acreage, with the exception of small non-operated acreage that we have backed into. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve its drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of our acreage, we retain the ability to adjust our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.

 

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, which brought our total gross acreage position in the Delaware Basin to approximately 11,190 gross acres at December 31, 2013. Following recent sales of certain leases and back-ins our current gross acreage is 34,921 as of December 31, 2014. Since our initial acquisition, and through December 31, 2014, 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 vast majority of our acreage.

 

5
 

 

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 3rd, 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 3rd Bone Spring, but the understanding of the relationship between the 3rd Bone Spring sand reservoir and the organic rich silts of the 2nd 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.

 

6
 

 

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 3rd 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 3rd Bone Spring has an ash fall structural marker that occurs in all the basinal wells. The 3rd 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 2nd 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 1st 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 1st Bone Spring Lime. The Lower Avalon is 500 feet below the top of the 1st 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, 2014, there was production from the SM Prewitt #1H, Locker State #1H, Graham #1H, Woods #1H, Vastar State #1V, Jackson #1H, Emily Bell #1H and Woods #2H wells. We currently have seven producing wells; the seventh of which is waiting on final completion. The SM Prewitt #1H 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

 

During 2015, depending on the pace of drilling and if oil prices improve, we may drill and complete an estimated ten additional gross horizontal wells on our acreage. Based on this plan, we would estimate that our capital expenditures for the next twelve months would be approximately $40 million, which includes costs for infrastructure and non-operated wells, but does not include the cost of any land acquisitions. However, 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 at such a high pace. We are not currently engaged in any drilling activity due to the reduced price of oil.

 

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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, 2013 and December 31, 2014, in each case with respect to our assets in the Permian Basin. The report covers 100% of our total reserves. The assumptions, data, methods and procedures employed by WPC are appropriate for the purpose served by the reports and WPC has used all methods and procedures as it considered necessary under the circumstances to prepare the reports.

 

WPC 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. WPC 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.

 

Roy C. Williamson, Jr. is the Chief Executive Officer and President of WPC and is the technical person primarily responsible for evaluating the proved reserves covered by this report. Mr. Williamson has 57 years’ experience in evaluating oil and gas reserves, including 46 years’ experience as a consulting reservoir engineer. Mr. Williamson holds a Bachelor of Science Degrees in Petroleum Engineering and Geological Engineering from the University of Oklahoma. He is a Registered Professional Engineer in the States of Texas and Colorado. He is a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the Society of Independent Professional Earth Scientists, and the Society of Petrophysicists and Well Log Analysts.

 

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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 2013 and 2014 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, WPC 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.

 

Arabella maintains 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. Arabella provides 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 Arabella;
     
  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.

 

9
 

 

The following table presents our estimated net proved oil and natural gas reserves and the present value of our reserves as of December 31, 2013 and December 31, 2014, based on the reserve reports prepared by 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.

 

   Historical(1) 
   December 31, 2014   December 31, 2013 
         
Estimated proved developed reserves:        
Oil (MBbls)   460.8    118.5 
Natural gas (MMcf)   1,656.2    211.4 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)   736.8    153.7 
Estimated proved undeveloped reserves:          
Oil (MBbls)   2,049.2    1,421.9 
Natural gas (MMcf)   6,148.7    2,986.0 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)   3,073.9    1,919.6 
Estimated net proved reserves:          
Oil (MBbls)   2,509.9    1,540.4 
Natural gas (MMcf)   7,804.8    3,197.3 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)        2,073.2 
Percent proved developed   19.3%   7.4%
Probable developed reserves          
Oil (MBbls)   -    - 
Natural gas (MMcf)   -    - 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)   -    - 
Probable undeveloped reserves          
Oil (MBbls)   -    2,961.5 
Natural gas (MMcf)   -    6,219.1 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)   -    3,998.0 
Possible developed reserves          
Oil (MBbls)   -    - 
Natural gas (MMcf)   -    - 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)   -    - 
Possible undeveloped reserves          
Oil (MBbls)   1,194.6    4,092.8 
Natural gas (MMcf)   2,448.9    8,594.9 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)   1,602.7    5,525.3 

 

(1) Estimates of reserves as of December 31, 2014 and December 31, 2013 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, 2014 and December 31, 2013, 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 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.

 

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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. 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, 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. As of December 31, 2013, our proved undeveloped reserves totaled 1,421,889 MBbls of oil and 2,985,966 MMcf of natural gas for a total of 1,919,550 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

 

Changes in PUDs that occurred during 2014 were primarily due to:

 

additions of 1,248,503 MBOE attributable to extensions resulting from strategic drilling of wells by Arabella to delineate Arabella’s acreage position;

 

the conversion of approximately 297,212 MBOE from PUDs into proved developed reserves from drilling of wells; and

 

the addition of approximately 203,083 MBOE from other changes including acquisition of working interests in our existing wells.

 

Costs incurred relating to the development of PUDs were approximately $17 million during 2014. 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 $40 million over the next twelve months, $100 million in 2016, $150 million in 2017 and $150 million in 2018. However, the forgoing is highly dependent on the price of oil and may be adjusted if prices remain depressed. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years. These anticipated lower drilling and completion costs are not incorporated into our proved reserve estimates as of December 31, 2014.

 

The following table shows how our total net proved reserves increased from December 31, 2013 to December 31, 2014.

 

   Amount of increase (decrease) 
Method of Increase (Decrease)  Oil
(Bbls)
   Natural Gas (Mcf) 
Production   (37,191)   (36,258)
Purchase and discoveries of minerals in place   1,006,733    4,643,774 

 

All of our PUD drilling locations are scheduled to be drilled prior to the end of 2018. As of December 31, 2014, our Woods #2H well included in total proved reserves was classified as proved developed non-producing.

 

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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.

 

   Historical 
   December 31, 2014   December 31, 2013 
Production Data:        
Oil (Bbls)   37,191    13,915 
Natural gas (Mcf)   36,258    11,048 
Combined volumes (BOE)   43,234    15,756 
Daily combined volumes (BOE/d)   118.5    43.2 
Average Prices(1):          
Oil (per Bbl)  $85.97   $96.45 
Natural gas (per Mcf)   4.23    6.88 
Combined (per BOE)   77.50    90.01 
Average Costs (per BOE):          
Lease operating expense  $37.78   $9.65 
Production Taxes   3.54    4.06 
Production Taxes as a % of sales   4.5    4.5 
Depreciation, depletion and amortization   33.41    29.78 
General and Administrative   116.32    34.54 

 

 (1) The average prices per barrel of oil and per BOE were $96.45 and $90.01, respectively, during the year ended December 31, 2013 and $85.97 and $77.50, respectively, during the year ended December 31, 2014.

 

Productive Wells

 

As of December 31, 2014, we owned an average 37% working interest in eight gross (2.96 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, 2014 relating to Arabella’s leasehold acreage:

 

   Developed Acreage(1)   Undeveloped Acreage(2)    Total Acreage 
Basin  Gross(3)   Net(4)   Gross(3)   Net(4)   Gross(3)    Net(4) 
Permian   10,774    1,876    24,147    3,095    34,921    4,972 

  

(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   19,911    4,450 
Ward County   640    398 
Pecos County   14,370    124 

 

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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, 2014, 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, 2014 reserve report to be drilled after the lease expiration.

 

Permian  2015   2016   2017   2018   2019 
Basin  Gross   Net   Gross   Net   Gross   Net   Gross   Net   Gross   Net 
December 31, 2014   13,290    2,125    4,934    270    6,438    2,645    -    -    -    - 

  

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,
2014
   December 31,
2013
 
   Gross   Net   Gross   Net 
                 
Development:                
Productive  -   -   -   - 
Dry   -    -    -    - 
Exploratory:                    
Productive   8.0    3.0    5.0    1.3 
Dry   -    -    -    - 
Total:                    
Productive   8.0    3.0    5.0    1.3 
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.

 

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We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For 2014, four purchasers accounted for the vast majority of our revenue: Occidental Energy Marketing Inc. (31%), Sunoco Partners (58%), Enterprise Crude Oil, LLC (7%) and Regency Energy Partners (5%). 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 Arabella 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 Arabella has 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.

 

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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.

 

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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 2014. 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 Arabella’s 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 believes 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.

 

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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 Arabella’s 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.

 

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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 2014 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 2015. 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 new 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.

 

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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 Arabella operates, 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.

 

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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.

 

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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 believes 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, 2014, we had fourteen 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.

 

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Facilities

 

Our corporate headquarters is located at 509 Pecan Street, Suite 200, Fort Worth, Texas, 76102. Our main telephone number is (432) 897-4755. This facility is leased at $93,587 per year through June of 2017. We also plan to 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.

 

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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 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.

 

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 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, 2014 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 financing and operations to meet its obligations, as they become payable.

 

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or 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.

 

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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 80.7%) 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 80.7% 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. We make and expect to continue 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 intend to finance our future capital expenditures with cash flow from operations, proceeds from offerings of our debt and equity securities and borrowings under our Senior Note facility. 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 2015 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 may result in a substantial lease renewal cost 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. 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, could result in the loss of acreage through lease expirations. Any such losses of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.

 

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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 intend to 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.

 

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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, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

 

As of December 31, 2014, we had identified 360 - 600 potential horizontal drilling locations in multiple horizons on our acreage based on 1,320 foot spacing. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. 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. In addition, we have identified 120 - 360 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. 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 may 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 could have 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 likely 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 may require 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 may be required to write down the carrying value of our oil and natural gas properties. Our properties serve as collateral for advances under our Senior Secured Note facility; a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. A write-down could also constitute 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.

 

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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.

 

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Part of our strategy 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.

 

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 (80.7%) 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.

 

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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.

 

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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.

 

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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.

 

Arbaella 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.

 

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Any significant reduction in our borrowing base under our Senior Note facility may negatively impact our ability to fund our operations.

 

Availability under our Senior Note facility is subject to a borrowing base determined by the PV10 value of our proved, developed, producing reserves. The borrowing base is subject to possible collateral borrowing base redeterminations based on our oil and natural gas reserves. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

 

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 may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, 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, 2014, we had $16 million drawn on our Senior Secured Note facility (see section entitled “Senior Secured Note Facility”). If in the future we sell additional Senior Secured Notes under the existing facility or 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.

 

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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.

 

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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.

 

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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

 

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, 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.

 

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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 and through November 21, 2014, 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 
2012:                        
First Quarter   8.20    8.20    7.75    7.75    0.36    0.25 
Second Quarter   8.20    8.10    7.85    7.75    0.37    0.20 
Third Quarter   8.20    8.10    7.90    7.77    0.30    0.20 
Fourth Quarter   8.20    8.20    8.00    7.89    0.33    0.10 
                               
2013:                              
First Quarter   8.35    8.17    8.18    8.18    0.22    0.06 
Second Quarter   8.30    8.17    8.08    8.08    0.55    0.23 
Third Quarter   8.25    8.25    8.13    8.08    0.45    0.11 
Fourth Quarter   8.25    8.25    8.25    7.25    0.85    0.22 
                               
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 

 

At April 14, 2015, the market price of the Company's ordinary shares was $4.97 per share.

 

As of December 31, 2014, 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, 2014.

 

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

 

In connection with our acquisition of Arabella Exploration Limited Liability Company on December 24, 2013, we issued 3,125,000 ordinary shares to six persons 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 issued to the individuals above were sold for all of the outstanding equity interests of Arabella Exploration Limited Liability Company. No underwriting discounts or commissions were paid with respect to such sales.

 

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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 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.

 

Between September 29, 2014 and November 7, 2014, we agreed to issue 112,500 ordinary shares for the purchase of working interests in certain of our properties. These shares have not yet been issued but will be issued 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.

 

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.

 

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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.

 

We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. 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 86% oil, no natural gas liquids and 14% natural gas for the year ended December 31, 2014, approximately 95% oil, no natural gas liquids and 5% natural gas for the year ended December 31, 2013. On December 31, 2014, our net acreage position in the Delaware Basin was approximately 4,972 net acres. On December 31, 2013, our net acreage position in the Delaware Basin was approximately 5,037 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 Exploration, Limited Liability Company, a Texas limited liability company (the “Acquisition”). On December 24, 2013, we consummated the Acquisition with Arabella Exploration Limited Liability Company, 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.

 

Future Activity

During 2015, depending on the pace of drilling and if oil prices improve, we may drill and complete an estimated ten additional gross horizontal wells on our acreage. Based on this plan, we would estimate that our capital expenditures for the next twelve months would be approximately $40 million, which includes costs for infrastructure and non-operated wells, but does not include the cost of any land acquisitions. However, 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 at such a high pace. 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, 2014, our average daily production was approximately 119 BOE, consisting of 102 Bbls/d of oil, 99 Mcf/d of natural gas and no natural gas liquids, this is a significant increase from the year ending December 31, 2013, when our average daily production was approximately 43 BOE, consisting of 38 Bbls/d of oil, 30 Mcf/d of natural gas and no natural gas liquids.

 

During 2014 our production was significantly lower than expected. With all of our wells online (excluding flush production) our estimated daily production capacity is between 400 and 500 BOE/d net, 300 to 375 BOE/d to our NRI. Due to a number of factors, in part to operational difficulties and drilling and reworking as well as the drop in oil prices in the second half of the year, our actual production was significantly lower than that amount. Our SM Prewitt #1H well spent the entire year shut in awaiting rework and our Vastar State #1V produced at a much lower rate than was expected for approximately 170 days of the year awaiting horizontal re-entry. During 2014 we began to put our wells on gas lift, which is one of the accepted methods of artificial lift being utilized in the area. This method of artificial lift utilizes the gas produced by the well to enhance production. Our Locker State #1H spent approximately 50 days being descaled and reworked and our Graham #1H well was off line for approximately 50 days. Our Jackson #1H well began production in February and spent approximately 40 days offline during the transfer to artificial lift. Our Emily Bell #1H began production in June and did not spend any days offline, but is still flowing naturally and not on artificial lift. In addition to days offline, we experienced significant difficulty and expense providing power to our wells. Power is required to operate our artificial lift systems and electrical service in the area of our wells has proved to be unreliable or non-existent. As a result we spent the bulk of 2014 relying upon diesel generators to power our artificial lift. Supply of diesel fuel to our generators also proved to be unreliable. We are currently in the process of fitting our wells with generators for our artificial lift systems powered by the actual gas produced by the wells, or have had electricity brought onto the lease. In addition to increased reliability and production, these new generators will significantly reduce the cost of operating our wells. We expect to see general improvement in the reliability of our wells with the new systems in place, however, future production will likely remain depressed until we are able to resume drilling activities, including the fracing of the Woods #2H and the horizontal re-entry of the Vastar State #1V.

 

Through the year ended December 31, 2014, we had participated in 8 gross (2.96 net) operated wells in the Delaware Basin.

 

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Reserves and pricing

 

In the table below, WPC estimated all of our proved reserves at December 31, 2014 and December 31. 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,
2014
   December 31, 2013 
         
Oil (MBbls)   2,509.9    1,540.4 
Natural gas (MMcf)   7,804.8    3,197.3 
Total (MBOE)   3,810.7    2,073.3 

 

   December 31,  2014   December 31,  2013 
   Unweighted Arithmetic
Average
First-Day-of-the-Month Prices
 
Oil (Bbls)  $85.54   $91.24 
Natural gas (Mcf)   5.51    6.07 

 

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, 2014 and December 31, 2013 our revenues were derived 94 and 95%, respectively, from oil sales, 0 and 0%, respectively, from natural gas liquids sales and 6% and 5%, 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 2014, West Texas Intermediate posted prices ranged from $53.45 to $107.52 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.99 to $8.12 per MMBtu. On December 31, 2014, the West Texas Intermediate posted price for crude oil was $53.45 per Bbl and the Henry Hub spot market price of natural gas was $3.14 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.

 

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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.

 

General and administrative expenses allocated from Arabella Petroleum Company. These are general and administrative costs that were subject to a cost sharing agreement with APC, which is owned and controlled by Jason Hoisager. These include a portion of the rent for office space, office equipment and administrative services.

 

   Year Ended 
   December 31,
2014
   December 31,
2013
 
         
Revenues:        
Oil and gas revenue  $3,408,296   $1,421,915 
Other operating revenue – gain on sale of oil and gas properties   3,084,917    - 
Total revenues   6,493,213    1,421,915 
Costs and expenses:          
Lease operating expenses   1,633,456    152,052 
Ad valorem and production taxes   153,231    64,033 
Depreciation, depletion and amortization   1,444,315    469,230 
Accretion of asset retirement obligation   1,770    663 
General and administrative expenses   5,029,056    412,268 
General and administrative expenses allocated from Arabella Petroleum Company   -    131,950 
Total costs and expenses   8,261,828    1,230,196 
Income (loss) from operations   (1,768,615)   191,719 
Other income (expense)         
Interest expense, related party   (40,722)   - 
Interest expense   (2,882,212)   - 
Total other income (expense)   (2,922,934)   - 
Net income (loss) before taxes   (4,691,549)   191,719 
Provision for income taxes   -    - 
Net income (loss)  $(4,691,549)  $191,719 

 

40
 

 

   December 31,   December 31, 
   2014   2013 
Production Data:        
Oil (Bbls)   37,191    13,915 
Natural gas (Mcf)   36,258    11,048 
Combined volumes (BOE)   43,234    15,756 
Daily combined volumes (BOE/d)   118.5    43.2 
Average Prices(1):          
Oil (per Bbl)  $85.97   $96.45 
Natural gas (per Mcf)   4.23    6.88 
Combined (per BOE)   77.50    90.01 
Average Costs (per BOE):          
Lease operating expense  $37.78   $9.65 
Production Taxes   3.54    4.06 
Production Taxes as a % of sales   4.5    4.5 
Depreciation, depletion and amortization   33.41    29.78 
General and Administrative   116.32    34.54 

 

Comparison of Years ended December 31, 2014 and December 31, 2013

 

Oil and Natural Gas Revenues. Our oil and natural gas revenues increased by $1,986,381, or 140%, to $3,408,296 for the year ended December 31, 2014, as compared to $1,421,915 for the year ended December 31, 2013. Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. The reason for the increase in revenues is due to increased sales of oil and natural gas due to the completion of wells in 2014. In 2014, the Jackson #1H and the Emily Bell #1H began production. Production from these wells, offset by significant declines in the prices for oil and natural gas in the second half of 2014, and the fact that we did not have meaningful production until the second quarter of 2013 accounted for the increase in revenue.

 

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. Contingent conditions on the sale of the Weatherby acreage may result in an additional $78,300 of revenue. We did not have any property sales in 2013. 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 increased from $152,052 in 2013 to $1,633,456 in 2014. This increase is the direct result of new wells that were completed in second half of 2013 and during 2014 as described under revenues, above. 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 remained the same for 2014 as compared to 2013. There was an overall increase in taxes due to the revenue increase 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 increased from $469,230 in 2013 to $1,444,315 in 2014. The increase is primarily related to increased production from the new wells discussed under revenue, above.

 

General and Administrative. General and administrative expenses increased from $412,268 in 2013 to $5,029,056 in 2014. These expenses relate primarily to salaries and wages, legal fees and professional fees. The increase is related to additional general and administrative costs relating to increased drilling and production activity in 2014, as well as increased legal, accounting and salary expenses, for 2014, as compared to 2013. A substantial portion of the increase in general and administrative costs in 2014 related to non-recurring events including, costs associated with obtaining financing, employment costs for positions related to development that did not occur due to the price of oil which have since been eliminated and due in part to onetime expenses relating to the Acquisition.

 

41
 

 

Liquidity and Capital Resources

 

Our primary source of liquidity has been a substantial increase in 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. Currently, our major source of our liquidity is the Senior Secured Note Facility entered into on September 2, 2014 (the “Notes”). 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 rapid and substantial decline in oil prices in the later part of 2014 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. Our current cash position, availability of financing from our Senior Secured Note facility and current level of operating cash flows may not, in aggregate, be 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 $15,632,034 as of December 31, 2014 largely consisting of notes payable in less than twelve months. Our net cash flow for the year ended December 31, 2014 was a decrease of $2,115,531, the components of which are described below. Our net cash flow for the year ended December 31, 2013 was an increase of $2,105,543. Depending on the pace of drilling and the oil and gas pricing environment, we may need approximately $40 million to fund our operations during the next twelve months (which we expect to be funded in large part by the Senior Secured Note Facility), 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 drill at such a high pace.

 

On September 2, 2014 we sold the first $16,000,000 of Notes under our $45,000,000 Senior Secured Note Facility. Future sales of Notes are subject to certain funding conditions. We expect that the proceeds from the first and future sales of these Notes will sustain our base drilling operations for the next twelve months, assuming we meet the conditions for future Notes sales and assuming that we choose to continue our drilling program in the light of depressed oil prices. There can be no assurance that we will meet these conditions or that we will continue to drill wells. In the event that we accelerate our planned drilling schedule or do not meet the conditions for future note sales we may require additional funding in 2015.

 

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 $2,613,600 for the year ended December 31, 2014, as compared to net cash provided by operating activities of $380,934 for the year ended December 31, 2013. The decrease in operating cash flows is largely a result of the loss from operations in 2014, excluding the $3,084,917 in gains related to sale of undeveloped and developed oil and gas properties in the year ended December 31, 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 $14,514,940 and $3,498,808 for the years ended December 31, 2014 and December 31, 2013, 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 $19,683,092 and $3,718,303, respectively. In 2013, we used $219,495 in prepaid drilling costs against actual drilling. We used cash for investing in property and equipment in the amounts of $496,969 for the year ended December 31, 2014. 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.

 

42
 

 

During the year ended December 31, 2013, the sole member, Jason Hoisager, transferred a carrying value of $6,014,340 in oil and gas properties from Arabella Petroleum Company, in exchange for a $3,007,170 non-interest bearing, unsecured loan to Jason Hoisager and an equity contribution in the amount of $3,007,170.

 

Financing Activities

 

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.

 

During 2013, Arabella received $5,183,417 of cash related to the Acquisition.

 

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 initial sale of $16,000,000 in Notes occurred on September 2, 2014 with further sales to be based upon reserve based performance hurdles. 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 us at any time without penalty. 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.

 

During the term of the Notes we can submit further reserve reports to the Investor, and if, in their discretion, the PV10 of our PDP has increased from the most recently submitted previous reserve report, they will acquire additional Notes in principal amounts on a dollar-for-dollar basis equal to said increase. The maximum amount of the Notes shall be $45,000,000 of total commitment and successive sales under this process must be at least $500,000 unless a lesser amount would constitute the entire remaining availability.

 

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

 

Currently, we are not engaged in any drilling activity due to the reduced price of oil. A return to our drill schedule will be dependent on future oil prices and planning. Depending on the pace of drilling and the oil and gas pricing environment, we could need approximately $40 million to fund our operations during the first twelve months of drilling (which we expect to be funded in large part by the Senior Secured Note Facility if it is still in place at that time and if we meet the conditions for its use), which will include minimum annual property lease payments, well expenditures and operating costs and expenses. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. We anticipate that while some of these expenditures will be funded by operations, the majority will come from outside funding sources, including the Notes.

 

However, the amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these 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 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.

 

43
 

 

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. No impairment of proved oil and natural gas properties was recorded for years ended December 31, 2014 and 2013.

 

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.

 

44
 

 

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, 2014 or December 31, 2013.

 

Income Taxes

 

During 2013 we were not a taxable entity for federal income tax purposes. Accordingly, we did not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of income because of the differences in the tax deductions for drilling wells.

 

Subsequent to the Acquisition, we were subject to Federal income taxes for 2014 but had a taxable loss 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 2014 and 2013.

 

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.

 

45
 

 

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.

 

46
 

 

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, 2014 and 2013 F-2
Consolidated Statements of Operations for the Years Ended December 31, 2014 and 2013 F-3
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2014 and 2013 F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014 and 2013 F-5
Notes to Consolidated Financial Statements F-6

 

47
 


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, 2014 and 2013, and the related consolidated statements of operations, changes in shareholders’ 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 audit 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 audit 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, 2014 and 2013, 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 approximately $4,180,000 and a working capital deficiency of approximately $15,632,000 as of December 31, 2014 largely consisting of notes payable 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 the 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 15, 2014

 

F-1
 

 

ARABELLA EXPLORATION, INC.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2014 AND 2013

 

   2014   2013 
ASSETS        
Current assets:        
    Cash and cash equivalents  $3,002   $2,118,533 
    Accounts receivable - oil and gas sales   814,689    436,830 
    Prepaid expenses   417,617    23,077 
           
        Total current assets   1,235,308    2,578,440 
           
Deposits and other assets   85,000    25,000 
Receivable from affiliate   381,801    - 
Property and equipment, net   315,826    - 
Oil and gas properties, successful efforts method - Net   29,043,146    13,249,367 
           
                Total assets  $31,061,081   $15,852,807 
           
LIABILITIES AND SHAREHOLDERS’ EQUITY          
           
Current liabilities:          
    Accounts payable and accrued liabilities  $876,058   $84,691 
    Payable to affiliates   32,550    - 
    Notes payable, net of discount   11,838,247    - 
    Accrued joint interest billings payable, related party    4,120,488    3,734,405 
           
        Total current liabilities   16,867,343    3,819,096 
           
Note payable to officer   3,007,170    3,007,170 
Asset retirement obligation   25,843    21,171 
                Total liabilities   19,900,356    6,847,437 
           
Commitments and contingencies          
           
Shareholders’ 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, 2014, and 4,829,826 at December 31, 2013   5,020    4,830 
Additional paid-in-capital   15,335,684    8,488,970 
        (Accumulated deficit) Retained earnings   (4,179,979)   511,570 
           
    Total shareholders’ equity   11,160,725    9,005,370 
           
                Total liabilities and shareholders’ equity  $31,061,081   $15,852,807 

 

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

 

F-2
 

 

ARABELLA EXPLORATION, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013

 

   2014   2013 
         
Revenues:        
Oil and gas revenue  $3,408,296   $1,421,915 
Other operating revenue – gain on sale of oil and gas properties   3,084,917    - 
           
 Total revenues   6,493,213    1,421,915 
           
Costs and expenses:          
Lease operating expenses   1,633,456    152,052 
Ad valorem and production taxes   153,231    64,033 
Depreciation, depletion and amortization   1,444,315    469,230 
Accretion of asset retirement obligation   1,770    663 
General and administrative expenses   5,029,056    412,268 
General and administrative expenses allocated from Arabella Petroleum Company, LLC   -    131,950 
           
Total costs and expenses   8,261,828    1,230,196 
(Loss) income from operations   (1,768,615)   191,719 
           
Other expense          
Interest expense, related party   (40,722)   - 
Interest expenses   (2,882,212)   - 
Other expenses   (2,922,934)   - 
           
Net (loss) income before taxes   (4,691,549)   191,719 
           
Provision for income taxes   -    - 
           
Net (loss) income  $(4,691,549)  $191,719 
           
Net (loss) income per ordinary share:          
Basic  $(0.95)  $0.06 
           
Diluted  $(0.95)  $0.06 
           
Weighted average ordinary shares outstanding:          
Basic   4,928,978    3,157,695 
           
Diluted   4,928,978    3,201,305 

 

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

 

F-3
 

 

ARABELLA EXPLORATION, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013

 

   Ordinary     

Retained

Earnings

     
   Shares   Paid-In   (Accumulated    
   Shares   Amount   Capital   Deficit)   Total 
Balance at December 31, 2012   3,125,000   $3,125   $125,436   $319,851   $448,412 
                          
Contributions by founder:                         
                          
Cash   -    -    40,000    -    40,000 
                          
General and administrative expenses   -    -    131,950    -    131,950 
                          
Oil and gas assets   -    -    3,009,832    -    3,009,832 
                          
Outstanding shares of Lone Oak Acquisition Corporation at the time of the reverse merger   1,704,826    1,705    5,181,752    -    5,183,457 
                          
Net income   -    -    -    191,719    191,719 
                          
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   -    -    -    (4,691,549)   (4,691,549)
                          
Balance at December 31, 2014   5,020,303   $5,020   $15,335,684   $(4,179,979)  $11,160,725 

 

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

 

F-4
 

 

ARABELLA EXPLORATION, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013

 

   2014    2013 
         
Cash flows from operating activities:        
Net income (loss)  $(4,691,549)  $191,719 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:          
        Depreciation, depletion and amortization   1,444,315    469,230 
        Accretion of asset retirement obligation   1,770    663 
        Amortization of interest expense   800,000    - 
        Amortization of deferred financing costs  1,001,597    - 
        Amortization of debt discount   1,079,280    - 
        Stock based compensation   391,265    - 
        Loss on disposal of fixed assets   48,840    - 
        Contribution recognized for allocated general and administrative expenses   -    131,950 
        Gain from sale of oil and gas properties   (3,084,917)   - 
        Changes in operating assets and liabilities:          
            Accounts receivable - oil and gas sales   (377,859)   (429,242)
            Prepaid expenses   (5,460)   (23,077)
            Deposits and other assets   (60,000)   (25,000)
            Receivable from affiliated companies   (381,801)   - 
            Payable to affiliated companies   32,550    - 
            Accrued joint interest billing payable   386,083    - 
            Accounts payable and accrued liabilities   791,367    64,691 
                Net cash (used in) provided by operating activities   (2,613,600)   380,934 
           
Cash flows from investing activities:          
    Additions to property and equipment   (496,969)   - 
    Additions to oil and gas properties   (19,683,092)   (3,718,303)
    Proceeds from sale of oil and gas properties   5,665,121    - 
    Prepaid drilling costs   -    219,495 
                Net cash used in investing activities   (14,514,940)   (3,498,808)
           
Cash flows from financing activities:          
Cash received in merger   -    5,183,417 
Cash contribution from shareholder   -    40,000 
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)   - 
Prepaid interest, Senior Secured Notes   (1,200,000)   -
Deferred financing cost   (1,787,000)   - 
                Net cash provided by financing activities   15,013,009    5,223,417 
           
Net (decrease) increase in cash and cash equivalents   (2,115,531)   2,105,543 
           
Cash and cash equivalents at beginning of year   2,118,533    12,990 
           
Cash and cash equivalents at end of year  $3,002   $2,118,533 
           
Cash for:          
Interest   $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  $428,321   $3,692,167 
Addition to oil and gas properties through Increase in Notes payable to officer  $-   $1,764,474 
Addition to oil and gas properties contributed by officer at cost  $-    3,009,832 
Capitalized imputed interest expense contributed by sole member related to member loans  $-   $2,662 
Increase in oil and gas properties through recognition of asset retirement obligation  $-   $18,208 

  

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

 

F-5
 

  

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, Limited Liability Company (“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 this date Arabella Petroleum Company, LLC, and 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 issue 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 whether the goals have been met for 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. 

 

F-6
 

 

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 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, 2014 had an accumulated deficit of approximately $4,180,000 and a working capital deficit of approximately $15,632,000 as of December 31, 2014 largely consisting of notes payable due in less than twelve months. 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.

 

In the event of a return to drilling, the Company expects that, depending on the pace of drilling and the pricing environment for oil and gas, it could need approximately $40 million to fund its operations during the first twelve months of activity, which will include minimum annual property lease payments, well expenditures and operating costs and expenses.

 

On September 2, 2014 the Company sold the first $16,000,000 of Notes under its $45,000,000 Senior Secured Note Facility (See Note 8 – Senior Secured Notes). Future Sales of Notes are subject to certain funding conditions. The Company expects that the proceeds from the first and future sales of these Notes will sustain its base drilling operations for the next twelve months, assuming it meets the conditions for future Notes sales. There can be no assurance that the Company will meet these conditions. In the event that the Company accelerates its planned drilling schedule or does not meet the conditions for future notes sales it may require additional funding in 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.

 

F-7
 

 

4. Summary of Significant Accounting Policies

 

Basis of Presentation

 

The accompanying consolidated financial statements of the Company include the accounts of Arabella Exploration Inc. and its wholly owned subsidiaries Arabella Exploration, Limited Liability Company, Arabella Operating, LLC and Arabella Midstream, LLC. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany transactions have been eliminated in consolidation. The Consolidated Statement of Operations includes the operations of Arabella LLC to the date of the reverse merger. Subsequent to the reverse merger, the operations also includes the operations of the Parent.

 

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, 2014 or 2013.

 

F-8
 

 

Property and Equipment

 

Property and equipment include furnitures 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. Gross property and equipment as of December 31, 2014 was $448,129 and net property and equipment was $315,826 after accumulated depreciation of $132,303 and depreciation expense of $132,303 in 2014. There was no property and equipment in 2013.

 

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 6 — Fair Value Measurements. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2014 and 2013.

 

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;

 

F-9
 

 

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, 2014 and 2013, 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 6 — 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 11—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.

 

F-10
 

 

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

 

During 2014, Arabella Exploration, Inc. was a taxable entity for federal income tax purposes as more fully described in Note 14 – 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, 2014 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 6 — Fair Value Measurements.

 

The Senior Secured Notes are 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. See Note 8 – Senior Secured Notes.

 

F-11
 

 

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.

 

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 2014 they were anti-dilutive and in 2013 the exercise of the offering warrants was contingent upon the effectiveness of a registration statement that had not yet been filed with the SEC. The calculation of diluted earnings per share does not include the potential dilutive impact of the Unit Purchase Option as it was not exercisable based on the Company’s average share and warrant prices.

 

The calculation of diluted earnings per share included the dilutive impact of the 6,600,000 Insider Warrants as they were sold pursuant to an exemption from the registration requirements of the Securities Act in 2013 but not in 2014 as they were anti-dilutive.

 

The calculation of diluted earnings per shares does not include the impact of the 1,300,000 Financing Warrants as they were issued in and anti-dilutive in 2014.

 

The calculation of diluted earnings per share does not include the impact of the 250,000 board of directors stock options as they were issued in and anti-dilutive in 2014.

 

The following table sets forth the computation of the basic and diluted earnings per share for the years ended December 31, 2014 and 2013:

 

   Year Ended 
   December 31,   December 31, 
   2014   2013 
         
Numerator for basic and diluted earnings per share:        
Net (loss) income  $(4,691,549)  $191,719 
           
Denominator:          
Denominator for basic earnings per ordinary shares – weighted average shares outstanding   5,020,303    3,157,695 
Effect of dilutive warrants   -    43,610 
Denominator for diluted earnings per ordinary share – weighted average shares outstanding   5,020,303    3,201,305 
           
Basic earnings per ordinary share  $(0.95)  $0.06 
Diluted earnings per ordinary share  $(0.95)  $0.06 

  

Recent Accounting Pronouncements

 

The Financial Accounting Standards Board (“FASB”) has issued 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.

 

In August 2014, the FASB issued Accounting Standards Update ("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 FASB has issued Accounting Standards Update (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 Accounting Standards Update No. 2014-09 (ASU 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 not permitted. 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.

 

F-12
 

  

The amendments are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments is permitted for financial statements that have not been previously issued. The adoption of this standard is not expected to have a material impact on the Company’s financial position and results of operations. The Company has elected early adoption of this standard.

 

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, 2014 is $25,843 (see Note 7 — 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.

 

F-13
 

 

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. No impairment charges on proved oil and natural gas properties were recorded for the years ended December 31, 2014 or 2013.

 

6. Oil and Gas Properties

 

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

 

   December 31, 
    2014    2013 
Proved oil and gas properties (1)  $25,914,778   $7,491,321 
Less: Accumulated depreciation, depletion, amortization and impairment (2)   (1,763,731)   (484,968)
Proved oil and gas properties, net   24,151,047    7,006,353 
Unproved oil and gas properties   4,892,099    6,243,014 
Total oil and gas properties, net  $29,043,146   $13,249,367 

 

(1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $23,575 and $20,267 at December 31, 2014 and 2013, respectively.
(2) Included in the depreciation, depletion, amortization and impairment is depletion of $1,312,012 and $484,968 in 2014 and 2013, respectively.

  

7. Asset Retirement Obligations

 

The following table reflects the changes in the Company’s ARO during the years ended December 31, 2014 and 2013:

 

   Year Ended December 31, 
   2014   2013 
Asset retirement obligation — beginning of period  $21,171   $2,963 
Additions to ARO from new properties   6,030    17,545 
Sales or abandonments of properties   (3,128)   - 
Accretion expense during period   1,770    663 
Asset retirement obligation — end of period  $25,843   $21,171 

 

8. Senior Secured Notes

 

On September 2, 2014 the Company entered into a $45,000,000 Senior Secured Note Facility (the “Notes”) with a New York based investor (the “Investor”). The initial sale of $16,000,000 in Notes occurred on September 2, 2014 with further sales to be based upon reserve based performance hurdles. 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 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 (the “Financing Warrants”). The Financing Warrants expire on September 2, 2019.

 

The Senior Secured Notes are carried 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.

 

F-14
 

 

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, 
   2014   2013 
Senior Secured Notes Payable  $16,00,000   $- 
Less:          
Debt discount – warrants   (3,237,840)   - 
Deferred financing costs   (3,004,790)   - 
Add:          
Accretion of debt discount   1,079,280    - 
Amortization of deferred financing cost   1,001,597    - 
           
Senior Secured Notes Payable, net of discount  $11,838,247   $- 

 

9. 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.

 

10. Note Payable to Officer

 

As of December 31, 2014 and 2013, 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.

 

11. 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.

 

F-15
 

 

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.

 

 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 year ended December 31, 2014 was $391,265. Unrecognized compensation expense as of December 31, 2014, relating to non-vested common stock options is approximately $167,685 and is expected to be recognized through the fourth quarter of 2015. At December 31, 2014, no options had been exercised and no options had been forfeited. As of December 31, 2014 the aggregate intrinsic value of these options was $0.

 

A summary of stock option activity for the year ended December 31, 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 

 

12. 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.

 

As December 31, 2014 and 2013, the Company owed Petroleum $4,120,488 and $3,734,405, 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 and $425,372 at December 31, 2014 and 2013, respectively. As of December 31, 2014 Petroleum owed the Company $381,801, a portion of the costs from the expense sharing agreement between the companies.

 

Petroleum also paid part of the general and administrative expenses for the companies during 2013 and allocated to Exploration $131,950 for the year ended December 31, 2013, respectively. No such expenses were allocated in 2014.

 

As of December 31, 2014, Petroleum has ceased to provide these services to the Company and AEX Operating, LLC, a wholly owned subsidiary of the Company, is the operator of record for the Company’s wells.

 

F-16
 

 

Arabella Minerals & Royalties, LLC (AMR) is a mineral and royalty fund controlled by Mr. Hoisager. AMR advanced the Company $8,800 in 2014.

 

Arabella Royalty Management, LLC (ARM) is a management company controlled by Mr. Hoisager. ARM advanced the Company $15,000 in 2014 which was subsequently repaid.

 

Masterson Royalty Fund, LLC (MRF) is a mineral and royalty fund controlled by Mr. Hoisager. MRF advanced the Company $2,000 in 2014.

 

Trans-Texas Land & Title, LLC (TTLT) has performed mineral ownership reports on lands for the Company in the past, and may do so in the future. Mr. Hoisager owns 100% of the equity interests of TTLT. TTLT advanced the Company $21,750 in 2014.

 

13. 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. Contingent conditions on the sale of the Weatherby acreage may result in an additional $78,300 of revenue.

 

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.

 

14. Income Taxes

 

As of December 23, 2013, Arabella 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 has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.

 

The Company had no income tax expense due to operating losses incurred for the year ended December 31, 2014 and the short period 2013 was not material.

 

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, 2014 and December 31, 2013:

 

   Year Ended December 31, 
   2014   2013 
Federal income tax benefit at statutory rate   (1,595,092)   - 
State taxes, net of federal benefit   107,927    - 
Permanent differences   1,624    - 
Other   (307)   - 
Change in valuation allowance   1,485,848    - 
Provision for income taxes   0    0 

 

The tax effects of temporary differences that gave rise to significant portions of deferred tax assets and liabilities at December 31, 2014 and December 31, 2013 are as follows:

   December 31, 
   2014   2013 
Deferred tax assets:        
Net operating loss carryforward  $7,153,641   $- 
Stock compensation   135,613    - 
Deferred tax liabilities:          
Fixed Assets   (53,011)   - 
Intangible drilling and other costs for oil and gas properties   (5,750,395)   - 
Net deferred tax assets and liabilities   1,485,848    - 
Less valuation allowance   (1,485,848)   - 
Total deferred tax assets and liabilities  $-   $- 

 

F-17
 

 

The Company had a net deferred tax asset related to federal net operating loss carry forwards of $21,040,122 and $0 at December 31, 2014 and 2013, respectively. The federal net operating loss carry forward will begin to expire in 2034. 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 $1,485,848 during 2014.

 

We file or have filed income tax returns in U.S. federal, state and foreign jurisdictions and are 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.

 

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 has not identified any uncertain tax positions requiring a reserve as of December 31, 2014 or 2013.

 

15. Significant Concentrations

 

Major customers. 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 our total sales, respectively. For the year ended December 31, 2013, sales, through Petroleum, to Sunoco Partners, and Enterprise Crude Oil accounted for approximately 78% and 10% of our total sales, respectively.   No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2014 and 2013. 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.

 

F-18
 

 

16. 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. The Company intends to lease new office space in Midland, Texas but has not yet done so.

 

Future minimum annual rental commitments under the non-cancelable office lease at December 31, 2014 are as follows:

 

2015  $93,587 
2016   93,587 
2017   46,794 
2018   - 
Thereafter   - 
   $233,968 

 

Drilling contracts. As of December 31, 2014 Arabella Operating did not have any drill rigs under contract.

 

Litigation. The Company is party to various legal proceedings from time to time arising in the ordinary course of business. The Company believes 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.

 

Asset Purchases. Between September 29, 2014 and November 7, 2014, we agreed to issue 112,500 ordinary shares for the purchase of working interests in certain of our properties. These shares have not yet been issued.

 

17. 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.

 

During the year ended December 31, 2013, properties totaling $4,774,306 were transferred to us from Petroleum, a company under common control and that transfer had a significant impact on our proved reserves. Accordingly, we have included supplemental oil and gas reserve information to give effect to the additional proved reserves on properties owned by Petroleum in prior periods and transferred to the Company.

 

F-19
 

 

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, 2014 and 2013, giving effect to reserves associated with properties owned by Petroleum during the period and transferred to us in 2013:

 

   Oil   Gas   BOE 
             
Balance at December 31, 2012   166,321    377,173    229,183 
                
Revisions   171,385    310,181    223,082 
Purchase and discoveries of minerals in place   1,216,611    2,521,015    1,636,780 
Production   (13,915)   (11,048)   (15,756)
                
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 

 

The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2014, and 2013, as recast, giving effect to reserves associated with properties owned by Petroleum during the period and transferred to us in 2013, was as follows (In thousands):

 

   2014   2013 
         
Future cash inflows  $244,585   $152,038 
Future costs:          
   Production   (54,325)   (31,849)
   Development   (57,282)   (31,885)
           
Future net cash inflows   132,978    88,304 
10% discount factor   (82,655)   (55,512)
           
Standardized measure of discounted net cash flows  $50,323   $32,792 

 

Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the year ended December 31, 2013, giving effect to reserves associated with properties owned by Petroleum during the period and transferred to us in 2013, was as follows (In thousands):

 

   2014   2013 
         
Standardized measure at beginning of period  $32,792   $2,708 
           
Sales, net of production costs   (1,622)   (1,206)
Revisions   -    7,372 
Purchases and discoveries of minerals in place   19,153    23,918 
           
Standardized measure at end of period  $50,323   $32,792 

 

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, 2014 and 2013 was as follows:

 

   Average Price  
   Oil     Gas   
         
December 31, 2013  $91.24   $6.07 
           
December 31, 2014  $85.54    $5.51 

 

F-20
 

 

Average prices for December 31, 2014 and 2013 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 Arabella’s estimated net proved oil and natural gas reserves and the present value of Arabella’s reserves as of December 31, 2014 and December 31, 2013, based on the reserve report prepared by WPC, and such reserve reports have been prepared in accordance with the rules and regulations of the SEC. All Arabella’s proved reserves included in the reserve reports are located in North America.

 

   December 31,
2014 (1)
   December 31,
2013 (1)
 
         
Estimated proved developed reserves:        
Oil (MBbls)   460.8    118.5 
Natural gas (MMcf)   1,656.2    211.4 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)   736.8    153.7 
Estimated proved undeveloped reserves:          
Oil (MBbls)   2,049.1    1,421.9 
Natural gas (MMcf)   6,148.7    2,985.9 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)   3,073.9    1,919.6 
Estimated net proved reserves:          
Oil (MBbls)   2,509.9    1,540.4 
Natural gas (MMcf)   7,804.8    3,197.3 
Natural gas liquids (MBbls)   -    - 
Total (MBOE)   3,807.8    2,073.3 
Percent proved developed   19.3%   7.4%
           
Probable reserves