Note 29 - Supplemental Oil and Gas Disclosures (Unaudited)



Capitalized Costs Relating to Oil and Gas Producing Activities
	United Kingdom		United States		Total
December 31, 2014:
Proved	$	935,557	$	54,201	$	989,758
Unproved		-		10,784		10,784
Total capitalized costs		935,557		64,985		1,000,542

Accumulated depreciation, depletion and amortization		(501,894)		(29,179)		(531,073)

Net capitalized costs	$	433,663	$	35,806	$	469,469

December 31, 2013:
Proved	$	1,043,927	$	40,742	$	1,084,669
Unproved		295,083		73,577		368,660
Total capitalized costs		1,339,010		114,319		1,453,329

Accumulated depreciation, depletion and amortization		(355,366)		(27,429)		(382,795)

Net capitalized costs	$	983,644	$	86,890	$	1,070,534



Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
		United Kingdom		United States		Total
Year Ended December 31, 2014:
Acquisition costs:
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration costs		18,976		20,107		39,083
Development costs		38,711		3,743		42,454
Total costs incurred	$	57,687	$	23,850	$	81,537

Year Ended December 31, 2013:
Acquisition costs:
Proved	$	—	$	—	$	—
Unproved		2,323		463		2,786
Exploration costs		39,202		11,644		50,846
Development costs		149,138		3,068		152,206
Total costs incurred	$	190,663	$	15,175	$	205,838

Year Ended December 31, 2012:
Acquisition costs:
Proved	$	143,004	$	1,176	$	144,180
Unproved		46,878		1,156		48,034
Exploration costs		46,730		15,397		62,127
Development costs		164,562		7,900		172,462
Total costs incurred	$	401,174	$	25,629	$	426,803



Results of Operations for Oil and Gas Producing Activities
		United Kingdom	United States		Total
Year Ended December 31, 2014:
Revenues	$	309,303	$	6,729	$	316,032
Production expenses		82,504		4,486		86,990
DD&A		172,343		1,825		174,168
Impairment of oil and gas properties		405,159		71,562		476,721
Income tax expense		(217,436)		(24,900)		(242,336)
Results of activities	$	(133,267)	$	(46,244)	$	(179,511)

Year Ended December 31, 2013:
Revenues	$	329,296	$	8,368	$	337,664
Production expenses		98,045		7,399		105,444
DD&A		137,739		3,242		140,981
Impairment of oil and gas properties		—		9,566		9,566
Income tax expense (benefit)		57,977		(4,144)		53,833
Results of activities	$	35,535	$	(7,695)	$	27,840

Year Ended December 31, 2012:
Revenues	$	207,181	$	11,877	$	219,058
Production expenses		51,568		6,968		58,536
DD&A		56,813		7,574		64,387
Impairment of oil and gas properties		—		53,072		53,072
Income tax expense (benefit)		61,256		(19,508)		41,748
Results of activities	$	37,544	$	(36,229)	$	1,315

Oil and Gas Reserves

Proved reserves are estimated quantities of oil, gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The reserve volumes presented are estimates only and should not be construed as being exact quantities. These reserves may or may not be recovered and may increase or decrease as a result of our future operations and changes in economic conditions. Our oil and gas reserves were audited by independent reserve engineers at December 31, 2014, 2013 and 2012.



	United Kingdom	United States	Total
Proved Oil Reserves (mbbls):
Proved reserves at January 1, 2012	4,060	41	4,101
Production	(1,994)	(3)	(1,997)
Purchases of reserves	11,071	—	11,071
Sales of reserves in place	—	(19)	(19)
Extensions and discoveries	1,992	—	1,992
Revisions of previous estimates	(1,396)	(13)	(1,409)
Proved reserves at December 31, 2012	13,733	6	13,739
Production	(3,017)	(1)	(3,018)
Purchases of reserves	—	—	—
Sales of reserves in place	—	—	—
Extensions and discoveries	—	—	—
Revisions of previous estimates	1,624	(3)	1,621
Proved reserves at December 31, 2013	12,340	2	12,342
Production	(2,564)	(8)	(2,572)
Purchases of reserves	—	—	—
Sales of reserves in place	—	—	—
Extensions and discoveries	—	73	73
Revisions of previous estimates	(3,813)	8	(3,805)
Proved reserves at December 31, 2014	5,963	75	6,038

Proved Developed Oil Reserves (mbbls):
At December 31, 2012	5,261	6	5,267
At December 31, 2013	5,659	2	5,661
At December 31, 2014	5,744	75	5,819



	United Kingdom	United States	Total
Proved Gas Reserves (mmcf):
Proved reserves at January 1, 2012	50,723	60,978	111,701
Production	(91)	(5,206)	(5,297)
Purchases of reserves	1,409	998	2,407
Sales of reserves in place	—	(5,213)	(5,213)
Extensions and discoveries	473	—	473
Revisions of previous estimates	4,387	(36,867)	(32,480)
Proved reserves at December 31, 2012	56,901	14,690	71,591
Production	(1,194)	(2,636)	(3,830)
Purchases of reserves	—	—	—
Sales of reserves in place	—	(4,200)	(4,200)
Extensions and discoveries	—	—	—
Revisions of previous estimates	(309)	3,921	3,612
Proved reserves at December 31, 2013	55,398	11,775	67,173
Production	(6,253)	(1,577)	(7,830)
Purchases of reserves	—	—	—
Sales of reserves in place	—	—	—
Extensions and discoveries	—	24,285	24,285
Revisions of previous estimates	(24,962)	(21,428)	(46,390)
Proved reserves at December 31, 2014	24,183	13,055	37,238

Proved Developed Gas Reserves (mmcf):
At December 31, 2012	3,147	14,690	17,837
At December 31, 2013	18,384	9,792	28,176
At December 31, 2014	24,183	11,456	35,639



	United Kingdom	United States	Total
Proved Reserves (mboe) (1):
Proved reserves at January 1, 2012	12,514	10,204	22,718
Production	(2,009)	(871)	(2,880)
Extensions and discoveries	2,071	—	2,071
Purchase of proved reserves, in place	11,306	166	11,472
Sale of reserves	—	(888)	(888)
Revisions of previous estimates	(665)	(6,157)	(6,822)
Proved reserves at December 31, 2012	23,217	2,454	25,671
Production	(3,216)	(440)	(3,656)
Extensions and discoveries	—	—	—
Purchase of proved reserves, in place	—	—	—
Sale of reserves	—	(700)	(700)
Revisions of previous estimates	1,572	651	2,223
Proved reserves at December 31, 2013	21,573	1,965	23,538
Production	(3,606)	(271)	(3,877)
Extensions and discoveries	—	4,120	4,120
Purchase of proved reserves, in place	—	—	—
Sale of reserves	—	—	—
Revisions of previous estimates	(7,973)	(3,563)	(11,536)
Proved reserves at December 31, 2014	9,994	2,251	12,245

Proved Developed Reserves (mboe):
At December 31, 2012	5,785	2,454	8,239
At December 31, 2013	8,723	1,634	10,357
At December 31, 2014	9,775	1,984	11,759

⁽¹⁾

Mboe is calculated as mbbls plus mmcf divided by 6.

Proved reserves decreased from 23.5 mmboe at December 31, 2013 to 12.2 mmboe at December 31, 2014 primarily due to:

The transfer of 8.0 mmboe of PUD reserves to probable undeveloped reserves. The transferred reserves are economically producible at December 31, 2014 and had they remained classified as proved would have had a standardized measure of discounted future net cash flows of approximately $75 million. The decision to transfer these PUD reserves was based on uncertainties that exist around the financing required to develop these PUD reserves in a reasonable amount of time due to our filing of Chapter 11 under the Bankruptcy Code including the potential consequences from our anticipated breach of our leverage covenant under our Amended Term Loan Facility which are further discussed in Note 3 – Voluntary Reorganization under Chapter 11.

The transfer of all PUD reserves related to our Columbus field of 1.8 mmboe were reclassified to contingent resources as of December 31, 2014 as the field development plan has not yet been approved.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows and future production and development costs are determined by applying average 12-month pricing for the year. Oil, gas and condensate prices are escalated only for fixed and determinable amounts under provisions in some contracts. Estimated future income taxes are computed using current statutory income tax rates where production occurs. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

At December 31, 2014 and 2013, the prices used to determine the estimates of future cash inflows were as follows:


	December 31,
	2014		2013
	Oil	Gas	Oil	Gas
	($/bbl)	($/mcf)	($/bbl)	($/mcf)
United Kingdom	98.72	8.10	104.45	10.38
United States	84.42	3.40	97.71	2.94

Estimated future cash inflows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.

The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment and the risks inherent in reserve estimates.



Standardized Measure of Discounted Future Net Cash Flows of Proved Reserves
	United Kingdom		United States		Total
December 31, 2014:
Future cash inflows	$	778,119	$	50,693	$	828,812
Future production costs		(282,945)		(14,810)		(297,755)
Future development costs		(357,373)		(100)		(357,473)
Future income tax expense		159,266		—		159,266

Future net cash flows (undiscounted)		297,067		35,783		332,850
Annual discount of 10% for estimated timing		(201,859)		10,974		(190,885)

Standardized measure of future net cash flows	$	498,926		24,809	$	523,735

December 31, 2013:
Future cash inflows	$	1,862,137	$	34,852	$	1,896,989
Future production costs		(571,347)		(12,202)		(583,549)
Future development costs		(593,958)		(605)		(594,563)
Future income tax expense		(133,495)		—		(133,495)

Future net cash flows (undiscounted)		563,337		22,045		585,382
Annual discount of 10% for estimated timing		43,152		6,548		49,700

Standardized measure of future net cash flows	$	520,185	$	15,497	$	535,682



Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows
	2014		2013		2012
Standardized measure, beginning of period	$	535,682	$	498,978	$	264,872
Net changes in prices and production costs		(133,641)		(33,792)		(33,520)
Future development costs incurred		91,872		140,436		172,462
Net changes in estimated future development costs		134,810		(132,092)		(193,359)
Revisions of previous quantity estimates		(428,696)		88,008		(56,525)
Extensions and discoveries		43,783		—		102,386
Accretion of discount		65,895		78,151		42,589
Changes in income taxes, net		152,102		104,891		(74,778)
Sale of oil and gas produced, net of production costs		(226,799)		(232,220)		(165,547)
Purchased reserves		—		—		457,033
Sales of reserves in place		—		(4,074)		(6,971)
Change in production, timing and other		288,727		27,396		(9,664)

Standardized measure, end of period	$	523,735	$	535,682	$	498,978