SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

12 Months Ended

Dec. 31, 2015

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

Costs Incurred

Costs incurred in oil and natural gas property acquisition, exploration and development activities, all of which are conducted within the continental United States, are summarized below:

	December 31,
	2015			2014			2013
Property acquisition costs - unproved	$	(9,635,309	)	$	1,105,782		$	3,865,932
Property acquisition costs - proved		7,587,965			3,349,473			8,539,134
Sales proceeds - unproved		(30,442	)		(359,667	)		(679,266	)
Sales proceeds - proved		-			(307,600	)		(718,000	)
Exploration costs		3,217,161			426,909			2,504,087
Development costs		1,121,654			20,139,409			11,910,179
Capitalized asset retirements costs		4,301,810			241,629			5,795,400
Total costs incurred	$	6,562,839		$	24,595,935		$	31,217,466

The Company sells oil and natural gas prospects.  The gains or losses from these sales are recorded as adjustments to the full cost pool under U.S. Securities and Exchange Commission (“SEC”) guidelines.  Prospect profits were $30,442, $28,616 and $50,346 for fiscal years 2015, 2014 and 2013, respectively.

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization:

	December 31,
	2015			2014
Oil and gas properties, full cost method:
Not subject to amortization:
Prospect inventory	$	7,719,857		$	14,913,126
Property acquisition costs - unproved		6,150,862			8,623,344
Well development costs - unproved		417,997			2,170,582
Subject to amortization:
Property acquisition costs - proved		58,393,861			50,744,401
Well development costs - proved		81,063,335			74,440,227
Capitalized costs - unsuccessful		60,549,824			52,539,407
Capitalized asset retirement costs		4,505,018			8,806,828
Total capitalized costs		218,800,754			212,237,915
Less accumulated depreciation, depletion and amortization		(117,304,945	)		(103,929,493	)
Net capitalized costs	$	101,495,809		$	108,308,422

Reserves

Proved natural gas and oil reserves are those quantities of natural gas and oil, which, by analysis of geosciences 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.  Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period (if the first day of the month occurs on a weekend or holiday, the previous business day is used), unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.  A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  The area of the reservoir considered as proved includes:  (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geosciences and engineering data.  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geosciences, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.  Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Developed natural gas and oil reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

The information below on the Company’s natural gas and oil reserves is presented in accordance with regulations prescribed by the SEC, with guidelines established by the Society of Petroleum Engineers’ Petroleum Resource Management System, as in effect as of the date of such estimates.  The Company’s reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations.  Accordingly, these estimates will change as future information becomes available and as commodity prices change.  Such changes could be material and could occur in the near term.

The Company does not prepare engineering estimates of proved oil and natural gas reserve quantities for all wells.  The Company only prepares engineering studies of estimated oil and natural gas quantities on a consolidated basis.  The Company has a quantity of interests that, individually, are immaterial and are excluded from prepared engineering studies.  Accounting sales volumes and receipts differ from amounts prepared by internal engineers and included in the following tables.

	2015			2014			2013
Barrels of oil and condensate:
Proved developed and undeveloped reserves:
Beginning of year		14,011,343			14,381,960			7,739,964
Revisions of previous estimates		(5,596,379	)		(565,143	)		(1,142,654	)
Purchases of oil and gas properties		103,387			472,132			7,959,600
Extensions and discoveries		769,661			51,993			92,152
Sale of oil and gas properties		-			-			-
Production		(321,687	)		(329,599	)		(267,102	)
End of year		8,966,325			14,011,343			14,381,960
Proved developed reserves - January 1,		2,347,482			2,099,701			1,474,015
Proved developed reserves - December 31,		2,117,559			2,347,482			2,099,701
Proved undeveloped reserves - January 1,		11,663,861			12,282,259			6,265,949
Proved undeveloped reserves - December 31,		6,848,766			11,663,861			12,282,259

	2015			2014			2013
Thousands of cubic feet of natural gas:
Proved developed and undeveloped reserves:
Beginning of year		35,259,522			38,372,369			31,071,137
Revisions of previous estimates		(11,436,325	)		(479,438	)		(8,281,139	)
Purchases of oil and gas properties		264,981			81,177			16,495,803
Extensions and discoveries		3,675,358			-			362,806
Sale of oil and gas properties		-			-			-
Production		(1,993,842	)		(2,714,586	)		(1,276,238	)
End of year		25,769,694			35,259,522			38,372,369
Proved developed reserves - January 1,		7,786,537			10,316,516			10,156,754
Proved developed reserves - December 31,		8,552,249			7,786,537			10,316,516
Proved undeveloped reserves - January 1,		27,472,985			28,055,853			20,914,383
Proved undeveloped reserves - December 31,		17,217,445			27,472,985			28,055,853

Revisions in 2015 to previously estimated reserves for both natural gas and crude oil were primarily caused by (i) commodity price reductions of 6,771,739 Mcf of natural gas and 3,427,849 Boe of oil and condensate causing wells to reach their economic limits sooner and causing some proved undeveloped locations to become uneconomic; (ii) upward revisions of 2,337,685 Mcf of natural gas and 1,127,131 Boe of oil and condensate primarily associated with increased performance of Bayou Hebert (La Posada) field; and (iii) reclassifying PUD reserves of 7,002,271 Mcf and 3,295,661 Boe of oil and condensate to probable reserves primarily in Masters Creek due to the current economic conditions and uncertainty in future development plans.

Internal Controls Over Reserve and Future Net Revenue Estimation

The Company’s principle engineer is the Executive Vice President and Chief Operating Officer and is the person primarily responsible for overseeing the preparation of the Company’s internal reserve estimates and for overseeing the independent petroleum engineering firm during the preparation of the Company’s reserve report.  His experience includes among other things, detailed evaluation of reserves and future net revenues for acquisitions, divestments, bank financing, long range planning, portfolio optimization, strategy and end of year financial reports.  He has a B.S. in Petroleum Engineering from Louisiana Tech University and is a member of the Society of Petroleum Engineers (the “SPE”).  His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers.  The Executive Vice President and Chief Operating Officer reports directly to the Company’s Chief Executive Officer.

At December 31, 2015, 2014 and 2013, Netherland, Sewell & Associates, Inc. performed an independent engineering evaluation in accordance with the definitions and regulations of the SEC to obtain an independent estimate of the Company’s proved reserves and future net revenues.

Third Party Procedures and Methods Review

The review consisted of 34 fields which included the Company’s major assets in the United States and encompassed 100 percent of the Company’s proved reserves and future net cash flows as of December 31, 2015, 2014, and 2013.  The Chief Operating Officer and the reservoir engineering staff presented the outside engineering firm with an overview of the data, methods and assumptions used in estimating reserves and future net revenues for each field.  The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating expenses and other relevant economic criteria.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures from the FASB concerning disclosures about oil and gas producing activities, and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff.  It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance.  Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

●  Future costs and oil and natural gas sales prices will probably differ from the average annual prices required to be used in these calculations;

●  Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

●  A 10 percent discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and

●  Future net revenues may be subject to different rates of income taxation.

The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved crude oil and natural gas reserves as of year-end is shown for Exploration for fiscal years 2015, 2014 and 2013.

	December 31,
	2015			2014			2013
Future cash inflows	$	438,816,500		$	1,339,372,300		$	1,450,469,000
Future oil and natural gas operating expenses		(129,636,500	)		(322,298,300	)		(334,883,800	)
Future development costs		(126,463,700	)		(405,900,900	)		(424,256,900	)
Future income tax expenses		(23,334,886	)		(133,467,940	)		(163,704,120	)
Future net cash flows		159,381,414			477,705,160			527,624,180
10% annual discount for estimating timing of cash flows		(53,318,652	)		(183,249,968	)		(202,270,201	)
Standardized measure of discounted future net cash flows	$	106,062,762		$	294,455,192		$	325,353,979

Estimates of future net cash flows from proved reserves of gas, oil, and condensate for fiscal years 2015, 2014 and 2013 are computed using the average first-day-of-the-month price during the 12-month period.  Prices used in computing year-end future cash flows were $50.28, $91.48 and $96.94 for crude oil and $2.59, $4.35 and $3.67 for natural gas for fiscal years 2015, 2014 and 2013, respectively.

The ceiling test for many companies following the full cost method of accounting for oil and natural gas properties, including the Company, could be negatively impacted by prolonged unfavorable crude oil and natural gas prices.  Future operating expenses and development costs are computed primarily by the Company’s petroleum engineer by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and natural gas reserves at the end of the year, based on the year-end costs and assuming continuation of existing economic conditions.

Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits.  A discount factor of ten percent was used to reflect the timing of future net cash flows.  The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties.  An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Change in Standardized Measure

Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for Exploration are summarized below:

	2015			2014			2013
Changes due to current year operation:
Sales of oil and natural gas, net of oil and natural gas operating expenses	$	(7,069,544	)	$	(25,270,455	)	$	(17,255,824	)
Extensions and discoveries		16,660			2,743,800			37,750,617
Purchases of oil and gas properties		2,268,907			12,827,533			215,427,459
Development costs incurred during the period that reduced future     development costs		4,052,919			9,178,400			100,500
Changes due to revisions in standardized variables:
Prices and operating expenses		(373,506,778	)		(42,125,763	)		(30,773,529	)
Income taxes		65,424,175			19,303,313			(38,340,467	)
Estimated future development costs		245,056,050			7,218,529			32,430,504
Quantity estimates		(80,454,131	)		(21,028,476	)		(107,070,514	)
Sale of reserves in place		-			-			-
Accretion of discount		37,672,481			43,124,820			27,910,664
Production rates, timing and other		(81,853,169	)		(36,870,488	)		(6,378,317	)
Net change		(188,392,430	)		(30,898,787	)		113,801,093
Beginning of year		294,455,192			325,353,979			211,552,886
End of year	$	106,062,762		$	294,455,192		$	325,353,979

Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pre-tax results.  Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis.