SEC Info - Sabine Oil & Gas Corp - ‘10-K/A’ for 12/31/13



	Oil					Natural Gas Liquids					Natural Gas
	(MBbls)					(MBbls)					(MMcf)
	United States		Italy	Total		United States		Italy	Total		United States		Italy		Total		Total MMcfe⁽¹⁾		Total MBoe⁽¹⁾
Balance at January 1, 2011	20,318		—	20,318		43,384		—	43,384		1,433,731		51,738		1,485,469		1,867,681		311,280
Revisions of previous estimates	(1,061	)	—	(1,061	)	(3,716	)	—	(3,716	)	(91,721	)	—		(91,721	)	(120,383	)	(20,064	)
Extensions and discoveries	17,816		—	17,816		8,262		—	8,262		144,094		—		144,094		300,562		50,094
Production	(2,491	)	—	(2,491	)	(3,154	)	—	(3,154	)	(88,497	)	—		(88,497	)	(122,367	)	(20,395	)
Sales of reserves in place	(2,989	)	—	(2,989	)	(347	)	—	(347	)	(1,091	)	—		(1,091	)	(21,107	)	(3,518	)
Purchases of reserves in place	—		—	—		—		—	—		—		—		—		—		—
Balance at December 31, 2011	31,593		—	31,593		44,429		—	44,429		1,396,516		51,738		1,448,254		1,904,386		317,398
Revisions of previous estimates	(6,151	)	—	(6,151	)	(6,023	)	—	(6,023	)	(479,009	)	(51,738	)	(530,747	)	(603,791	)	(100,632	)
Extensions and discoveries	16,574		—	16,574		6,929		—	6,929		93,643		—		93,643		234,661		39,110
Production	(3,146	)	—	(3,146	)	(3,489	)	—	(3,489	)	(81,008	)	—		(81,008	)	(120,818	)	(20,136	)
Sales of reserves in place	(5,168	)	—	(5,168	)	(591	)	—	(591	)	(17,309	)	—		(17,309	)	(51,863	)	(8,644	)
Purchases of reserves in place	—		—	—		—		—	—		—		—		—		—		—
Balance at December 31, 2012	33,702		—	33,702		41,255		—	41,255		912,833		—		912,833		1,362,575		227,096
Revisions of previous estimates	(3,394	)	—	(3,394	)	(1,973	)	—	(1,973	)	22,032		—		22,032		(10,170	)	(1,695	)
Extensions and discoveries	11,617		—	11,617		4,602		—	4,602		51,105		—		51,105		148,419		24,737
Production	(2,271	)	—	(2,271	)	(2,521	)	—	(2,521	)	(46,676	)	—		(46,676	)	(75,428	)	(12,571	)
Sales of reserves in place	(22,980	)	—	(22,980	)	(29,652	)	—	(29,652	)	(484,703	)	—		(484,703	)	(800,495	)	(133,416	)
Purchases of reserves in place	—		—	—		—		—	—		—		—		—		—		—
Balance at December 31, 2013	16,674		—	16,674		11,711		—	11,711		454,591		—		454,591		624,901		104,150
Proved developed reserves at:
January 1, 2011	13,421		—	13,421		24,120		—	24,120		886,644		25,869		912,513		1,137,759		189,627
December 31, 2011	14,149		—	14,149		23,170		—	23,170		814,160		—		814,160		1,038,074		173,012
December 31, 2012	12,315		—	12,315		25,518		—	25,518		710,288		—		710,288		937,286		156,214
December 31, 2013	6,151		—	6,151		6,855		—	6,855		336,342		—		336,342		414,378		69,063
Proved undeveloped reserves at:
January 1, 2011	6,897		—	6,897		19,264		—	19,264		547,087		25,869		572,956		729,922		121,654
December 31, 2011	17,444		—	17,444		21,259		—	21,259		582,356		51,738		634,094		866,312		144,385
December 31, 2012	21,387		—	21,387		15,737		—	15,737		202,545		—		202,545		425,289		70,882
December 31, 2013	10,523		—	10,523		4,856		—	4,856		118,249		—		118,249		210,523		35,087

___________________________________________


(1)	Oil and natural gas liquids are converted to gas-equivalents using a conversion of six Mcf “equivalent” per barrel of oil or natural gas liquids. Likewise, natural gas is converted to oil-equivalents using a conversion of one barrel of oil “equivalent” per six Mcf of natural gas. These conversions are based on energy equivalence and not price equivalence.

Revisions of Previous Estimates

In 2013, net negative revisions of 10 Bcfe were comprised of (i) the reclassification of 41 Bcfe of proved undeveloped reserves (“PUDs”) to probable undeveloped reserves for PUDs that are not expected to be developed five years from the time the reserves were initially disclosed, (ii) negative performance revisions of 9 Bcfe, and positive pricing revisions of 40 Bcfe due primarily to the increase in price of natural gas used in calculating proved reserves. In 2012, net negative revisions of 604 Bcfe were primarily associated with lower natural gas and natural gas liquids prices, which caused certain natural gas-weighted projects to no longer meet economic investment criteria based on the unweighted arithmetic average of the first-day-of-the-month commodity prices utilized in calculating the reserve estimates. In addition, lower natural gas prices also delayed Forest’s initial expected development time frame for drilling certain of its proved undeveloped natural gas locations beyond five years from the time the associated reserves were originally recorded. Accordingly, these PUDs were reclassified to probable undeveloped reserves in 2012. Additionally, all 52 Bcfe of the Company’s Italian PUDs were reclassified to probable due to an Italian regional regulatory body’s 2012 denial of the Company’s environmental impact assessment associated with the Company’s proposal to commence natural gas production from wells that it drilled and completed in 2007. The Company is currently appealing the region’s denial; however, until the region’s denial is reversed or overturned, the Company determined that it could no longer conclude with reasonable certainty that its Italian natural gas reserves are producible. In 2011, the net negative revisions of 120 Bcfe were primarily the result of the write-off of PUDs pursuant to the five year limitation and the write-off of natural gas reserves associated with a deep gas project in South Louisiana.

Extensions and Discoveries

In 2013, the Company had 148 Bcfe of extensions and discoveries, which were primarily due to exploration and development activities in the Eagle Ford in South Texas and Cotton Valley in East Texas. In 2012, the Company had 235 Bcfe of extensions and discoveries, which were primarily due to exploration and development activities in the Texas Panhandle and Eagle Ford in South Texas. In 2011, the Company had 301 Bcfe of extensions and discoveries, which were also primarily due to exploration and development activities in the Texas Panhandle and Eagle Ford in South Texas.

Sales of Reserves in Place

Sales of reserves in place for each of the years presented in the table above represent the sale of oil and natural gas property interests. See Note 2 for a description of these asset divestitures.

Aggregate Capitalized Costs

The aggregate capitalized costs relating to oil and gas producing activities were as follows as of the dates indicated:



	December 31,
	2013			2012
	(In Thousands)
Costs related to proved properties	$	9,213,668		$	9,696,498
Costs related to unproved properties	53,645			277,798
	9,267,313			9,974,296
Less accumulated depletion⁽¹⁾	(8,460,589		)	(8,237,186		)
	$	806,724		$	1,737,110

____________________________________________


(1)	Includes inception-to-date ceiling test write-downs.

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31, 2013, 2012, and 2011:



	United States		Italy		Total
	(In Thousands)
2013
Property acquisition costs:
Proved properties	$	—	$	—	$	—
Unproved properties	7,117		—		7,117
Exploration costs	129,946		—		129,946
Development costs	213,127		—		213,127
Total costs incurred⁽¹⁾	$	350,190	$	—	$	350,190
2012
Property acquisition costs:
Proved properties	$	—	$	—	$	—
Unproved properties	64,123		—		64,123
Exploration costs	268,153		700		268,853
Development costs	398,941		182		399,123
Total costs incurred⁽¹⁾	$	731,217	$	882	$	732,099
2011
Property acquisition costs:
Proved properties	$	—	$	—	$	—
Unproved properties	204,484		—		204,484
Exploration costs	286,412		1,003		287,415
Development costs	417,469		366		417,835
Total costs incurred⁽¹⁾	$	908,365	$	1,369	$	909,734

____________________________________________


(1)	Includes amounts relating to changes in estimated asset retirement obligations of $8.6 million, $6.1 million, and $3.1 million recorded during the years ended December 31, 2013, 2012, and 2011, respectively.

Results of Operations from Oil and Gas Producing Activities

Results of operations from oil and gas producing activities for the years ended December 31, 2013, 2012, and 2011 are presented below.



	United States			Italy			Total
	(In Thousands, except per Mcfe amounts)
2013
Oil, natural gas, and natural gas liquids sales	$	441,341		$	—		$	441,341
Expenses:
Production expense	103,427			—			103,427
Depletion expense	165,767			—			165,767
Ceiling test write-down of oil and natural gas properties	57,636			—			57,636
Accretion of asset retirement obligations	2,760			74			2,834
Income tax benefit	(707		)	—			(707		)
Total expenses	328,883			74			328,957
Results of operations from oil and gas producing activities	$	112,458		$	(74	)	$	112,384
Depletion rate per Mcfe	$	2.20		$	—		$	2.20
2012
Oil, natural gas, and natural gas liquids sales	$	605,523		$	—		$	605,523
Expenses:
Production expense	156,909			—			156,909
Depletion expense	275,886			—			275,886
Ceiling test write-down of oil and natural gas properties	957,587			34,817			992,404
Accretion of asset retirement obligations	6,487			62			6,549
Income tax expense	173,437			—			173,437
Total expenses	1,570,306			34,879			1,605,185
Results of operations from oil and gas producing activities	$	(964,783	)	$	(34,879	)	$	(999,662	)
Depletion rate per Mcfe	$	2.28		$	—		$	2.28
2011
Oil, natural gas, and natural gas liquids sales	$	703,531		$	—		$	703,531
Expenses:
Production expense	153,518			—			153,518
Depletion expense	213,866			—			213,866
Accretion of asset retirement obligations	5,973			44			6,017
Income tax expense	89,135			—			89,135
Total expenses	462,492			44			462,536
Results of operations from oil and gas producing activities	$	241,039		$	(44	)	$	240,995
Depletion rate per Mcfe	$	1.75		$	—		$	1.75

Standardized Measure of Discounted Future Net Cash Flows

Future oil, natural gas, and NGL sales are calculated applying the prices used in estimating the Company’s proved oil, natural gas, and NGL reserves to the year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end. Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved reserves, less the tax bases of the properties involved. The future income tax expenses give effect to tax deductions, credits, and allowances relating to the proved reserves. All cash flow amounts, including income taxes, are discounted at 10%.

Changes in the demand for oil, natural gas, and NGLs, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the Company’s proved reserves. Management does not rely upon the information that follows in making investment decisions.



	December 31, 2013
	United States			Italy		Total
	(In Thousands)
Future oil, natural gas, and natural gas liquids sales	$	3,459,749		$	—	$	3,459,749
Future production costs	(1,165,344		)	—		(1,165,344		)
Future development costs	(676,684		)	—		(676,684		)
Future income taxes	(18,441		)	—		(18,441		)
Future net cash flows	1,599,280			—		1,599,280
10% annual discount for estimated timing of cash flows	(864,672		)	—		(864,672		)
Standardized measure of discounted future net cash flows	$	734,608		$	—	$	734,608



	December 31, 2012
	United States			Italy		Total
	(In Thousands)
Future oil, natural gas, and natural gas liquids sales	$	6,929,652		$	—	$	6,929,652
Future production costs	(2,166,681		)	—		(2,166,681		)
Future development costs	(1,444,144		)	—		(1,444,144		)
Future income taxes	(142,383		)	—		(142,383		)
Future net cash flows	3,176,444			—		3,176,444
10% annual discount for estimated timing of cash flows	(1,779,347		)	—		(1,779,347		)
Standardized measure of discounted future net cash flows	$	1,397,097		$	—	$	1,397,097



	December 31, 2011
	United States			Italy			Total
	(In Thousands)
Future oil, natural gas, and natural gas liquids sales	$	10,427,716		$	576,364		$	11,004,080
Future production costs	(2,692,993		)	(199,054		)	(2,892,047		)
Future development costs	(2,008,824		)	(18,692		)	(2,027,516		)
Future income taxes	(940,526		)	(130,836		)	(1,071,362		)
Future net cash flows	4,785,373			227,782			5,013,155
10% annual discount for estimated timing of cash flows	(2,499,631		)	(125,783		)	(2,625,414		)
Standardized measure of discounted future net cash flows	$	2,285,742		$	101,999		$	2,387,741

Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last three years is as follows:



	December 31, 2013
	United States
	(In Thousands)
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at beginning of year	$	1,397,097
Changes resulting from:
Sales of oil, natural gas, and NGL net of production costs	(337,914		)
Net changes in prices and future production costs	222,516
Net changes in future development costs	50,568
Extensions, discoveries, and improved recovery	295,585
Development costs incurred during the period	128,482
Revisions of previous quantity estimates	(114,712		)
Changes in production rates, timing, and other	19,321
Sales of reserves in place	(1,099,372		)
Purchases of reserves in place	—
Accretion of discount on reserves at beginning of year	143,432
Net change in income taxes	29,605
Total change for year	(662,489		)
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at end of year	$	734,608

The computation of the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2013 was based on average prices and year-end costs. The Henry Hub average natural gas price and West Texas Intermediate average oil price during the twelve-month period prior to December 31, 2013 were $3.67 per MMBtu and $97.33 per barrel, respectively.



	December 31, 2012
	United States			Italy			Total
	(In Thousands)
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at beginning of year	$	2,285,742		$	101,999		$	2,387,741
Changes resulting from:
Sales of oil, natural gas, and NGL net of production costs	(448,614		)	—			(448,614		)
Net changes in prices and future production costs	(1,226,494		)	(9,264		)	(1,235,758		)
Net changes in future development costs	(4,188		)	—			(4,188		)
Extensions, discoveries, and improved recovery	572,516			—			572,516
Development costs incurred during the period	140,111			—			140,111
Revisions of previous quantity estimates	(203,987		)	(151,578		)	(355,565		)
Changes in production rates, timing, and other	(34,665		)	—			(34,665		)
Sales of reserves in place	(213,683		)	—			(213,683		)
Purchases of reserves in place	—			—			—
Accretion of discount on reserves at beginning of year	259,393			3,923			263,316
Net change in income taxes	270,966			54,920			325,886
Total change for year	(888,645		)	(101,999		)	(990,644		)
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at end of year	$	1,397,097		$	—		$	1,397,097

The computation of the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2012 was based on average prices and year-end costs. The Henry Hub average natural gas price and West Texas Intermediate average oil price during the twelve-month period prior to December 31, 2012 were $2.76 per MMBtu and $94.79 per barrel, respectively.



	December 31, 2011
	United States			Italy			Total
	(In Thousands)
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at beginning of year	$	1,964,920		$	205,526		$	2,170,446
Changes resulting from:
Sales of oil, natural gas, and NGL net of production costs	(550,013		)	—			(550,013		)
Net changes in prices and future production costs	272,027			(153,313		)	118,714
Net changes in future development costs	(55,725		)	(697		)	(56,422		)
Extensions, discoveries, and improved recovery	667,323			—			667,323
Development costs incurred during the period	231,270			—			231,270
Revisions of previous quantity estimates	(220,389		)	—			(220,389		)
Changes in production rates, timing, and other	(132,714		)	(40,508		)	(173,222		)
Sales of reserves in place	(107,742		)	—			(107,742		)
Purchases of reserves in place	—			—			—
Accretion of discount on reserves at beginning of year	226,354			31,949			258,303
Net change in income taxes	(9,569		)	59,042			49,473
Total change for year	320,822			(103,527		)	217,295
Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and NGL reserves, at end of year	$	2,285,742		$	101,999		$	2,387,741

The computation of the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2011 was based on average prices and year-end costs. The Henry Hub average natural gas price and West Texas Intermediate average oil price during the twelve-month period prior to December 31, 2011 were $4.12 per MMBtu and $96.08 per barrel, respectively.

This ‘10-K/A’ Filing	Date	Other Filings

Filed on:	10/1/14	10-Q/A, 8-K
For Period end:	12/31/13	10-K, ARS
	12/31/12	10-K, ARS
	12/31/11	10-K, ARS
	1/1/11
		List all Filings

Sabine Oil & Gas Corp – ‘10-K/A’ for 12/31/13 – ‘R21’

On: Wednesday, 10/1/14, at 4:47pm ET · For: 12/31/13 · Accession #: 38079-14-80 · File #: 1-13515

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Amendment to Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34
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‘R21’ — Supplemental Financial Data-Oil and Gas Producing Activities (Unaudited)

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Dates Referenced Herein and Documents Incorporated by Reference