Cimarex Resolute LLC - 10-K filing on 2014-03-10

Supplemental Oil and Gas Information (Tables)

12 Months Ended

Dec. 31, 2013

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

Costs incurred during 2013, 2012 and 2011 related to oil and gas property acquisition, exploration and development activities, including the fair value of oil and gas properties acquired in the Resolute Transaction are summarized as follows (in thousands):


	2013		2012		2011
Acquisition costs
Proved	$	155,958	$	166,951	$	53,577
Unproved		121,362		125,059		26,135
Exploration costs		150,072		120,570		72,730
Development costs*		97,308		100,579		77,210

Total	$	524,700	$	513,159	$	229,652

*	Includes $20.0 million, $16.2 million and $15.8 million of acquired CO₂ during 2013, 2012 and 2011, respectively_.

Net Capitalized Costs Related to Resolute's Oil and Gas Producing Activities

Net capitalized costs related to Resolute’s oil and gas producing activities at December 31, 2013 and December 31, 2012 were as follows (in thousands):


	2013			2012
Proved oil and gas properties	$	1,544,942		$	1,231,167
Unevaluated oil and gas properties, not subject to amortization		274,420			185,579
Accumulated depletion, depreciation and amortization		(491,279	)		(189,578	)

Oil and gas properties, net	$	1,328,083		$	1,227,168

Changes in Estimated Reserves

Presented below is a summary of the changes in estimated reserves (in thousands):


	Oil (Bbl)			Gas (Mcf)			NGL (Bbl)			Oil Equivalent (Boe)⁽¹⁾
Proved reserves as of January 1 , 2011		50,232			39,098			7,919			64,669
Purchases of minerals in place		1,811			5,251			1,340			4,026
Production		(2,299	)		(3,415	)		(17	)		(2,885	)
Extensions, discoveries and other additions		1,204			890			—			1,352
Sales of minerals in place		(291	)		(8	)		—			(293	)
Revisions of previous estimates		2,184			(6,659	)		(3,145	)		(2,071	)

Proved reserves as of December 31, 2011		52,841			35,157			6,097			64,798
Purchase of minerals in place		9,463			10,375			2,182			13,374
Production		(2,773	)		(3,567	)		(41	)		(3,409	)
Extensions, discoveries and other additions ⁽²⁾		4,115			3,400			243			4,924
Sales of minerals in place		(2,391	)		(735	)		(203	)		(2,717	)
Revisions of previous estimates		1,302			3,091			(14	)		1,804

Proved reserves as of December 31, 2012		62,557			47,721			8,264			78,774
Purchase of minerals in place		4,592			10,821			1,422			7,818
Production		(3,499	)		(4,565	)		(207	)		(4,467	)
Extensions, discoveries and other additions ⁽²⁾		4,038			6,128			746			5,805
Sales of minerals in place		(5,124	)		(3,379	)		(219	)		(5,906	)
Revisions of previous estimates ⁽³⁾		(15,053	)		(14,337	)		(5,189	)		(22,630	)

Proved reserves as of December 31, 2013		47,511			42,389			4,817			59,394

Proved developed reserves:
As of December 31, 2013		38,791			29,488			3,136			46,842
As of December 31, 2012		39,288			25,568			2,668			46,217
As of December 31, 2011		32,347			17,523			1,603			36,871
Proved undeveloped reserves:
As of December 31, 2013		8,720			12,901			1,681			12,552
As of December 31, 2012		23,268			22,153			5,596			32,557
As of December 31, 2011		20,494			17,634			4,494			27,927

In accordance with SEC and Financial Accounting Standards Board (“FASB”) requirements, our estimated net proved reserves and standardized measure at December 31, 2013, were determined utilizing prices equal to the respective twelve-month unweighted arithmetic average of first day of the month prices, resulting in an average NYMEX West Texas Intermediate oil price of $96.94 per Bbl for the Aneth Properties and Plains Marketing, L.P. West Texas Intermediate oil price of $93.42 per Bbl for the Permian and Wyoming Properties, and an average Henry Hub spot market gas price of $3.67 per one million British thermal units (“MMBtu”). At December 31, 2012 and 2011, we used an average NYMEX West Texas Intermediate oil price of $94.71 and $96.19 per Bbl, and an average Henry Hub spot market gas price of $2.76 and $4.12 per MMBtu, respectively.

Extensions, discoveries and other additions in 2013 are primarily related to new wells drilled and new proved undeveloped reserve locations in the Permian Basin and in 2012 were related to new proved undeveloped reserve locations in Williston Basin in North Dakota and in Aneth Field in Utah and new wells drilled in the Permian Basin in Texas.

Decreases in proved reserves associated with revisions of previous estimates resulted from management’s decision to allocate more of its 2014 capital expenditures toward exploitation drilling of higher expected rates-of-return horizontal wells in the Permian Basin and less capital towards development projects in Aneth Field. Deferral of these projects to 2015 and beyond reduced proved undeveloped reserves by approximately 25 MMBoe, as these projects are no longer expected to be converted to developed reserves within five years after their initial recognition as proved reserves as required under SEC rules, offset by approximately 3 MMBoe converted to proved developed during 2013. The deferred projects (the remaining portion of Aneth Unit Phase 4 CO₂ injection, approximately 8 MMBoe; the remaining portion of McElmo Unit DCIIC CO₂ injection, approximately 8 MMBoe; and Aneth Field membrane plant, approximately 7 MMBoe) will be again eligible for classification as proved undeveloped reserves, at such time as management adopts a definitive plan to complete the projects.

Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following summary sets forth Resolute’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by FASB ASC Topic 932:


	December 31,
	2013			2012			2011
	(in thousands)
Future cash inflows	$	4,647,000		$	5,983,000		$	5,190,000
Future production costs		(2,050,000	)		(2,678,000	)		(2,081,000	)
Future development costs		(547,000	)		(832,000	)		(648,000	)
Future income taxes		(398,000	)		(645,000	)		(733,000	)

Future net cash flows		1,652,000			1,828,000			1,728,000
10% annual discount for estimated timing of cash flows		(759,000	)		(956,000	)		(912,000	)

Standardized measure of discounted future net cash flows	$	893,000		$	872,000		$	816,000

Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

The principal sources of change in the standardized measure of discounted future net cash flows are:


	December 31,
	2013			2012			2011
	(in thousands)
Standardized measure, beginning of year	$	872,000		$	816,000		$	587,000
Sales of oil and gas produced, net of production costs		(206,000	)		(157,000	)		(105,000	)
Net changes in prices and production costs		61,000			(201,000	)		274,000
Purchases of minerals in place		106,000			205,000			43,000
Sales of minerals in place		(84,000	)		(49,000	)		(5,000	)
Previously estimated development costs incurred during the year		89,000			102,000			64,000
Extensions and discoveries		111,000			105,000			25,000
Changes in estimated future development costs		(64,000	)		(102,000	)		(65,000	)
Revisions of previous quantity estimates		(203,000	)		39,000			11,000
Accretion of discount		79,000			77,000			60,000
Net change in income taxes		67,000			72,000			(53,000	)
Changes in timing and other		65,000			(35,000	)		(20,000	)

Standardized measure, end of year	$	893,000		$	872,000		$	816,000