Callon Petroleum Company Annual report pursuant to Section 13 and 15(d)

Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Natural Gas Properties (unaudited)

Supplemental Information on Oil and Natural Gas Properties (unaudited)

12 Months Ended

Dec. 31, 2016

Supplemental Information on Oil and Natural Gas Properties (Unaudited) [Abstract]

Supplemental Information on Oil and Natural Gas Properties (unaudited)

Note 13 – Supplemental Information on Oil and Natural Gas Properties (Unaudited)

The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States.



	For the Year Ended December 31,
	2016		2015		2014
Evaluated Properties (a)
Beginning of period balance	$	2,335,223	$	2,077,985	$	1,701,577
Capitalized G&A expenses		12,222		10,529		10,071
Property acquisition costs (b)		216,561		26,726		94,541
Exploration costs		38,612		81,320		118,251
Development costs		151,735		138,663		153,545
End of period balance	$	2,754,353	$	2,335,223	$	2,077,985
Unevaluated Properties (a)(c)
Beginning of period balance	$	132,181	$	142,525	$	43,222
Property acquisition costs (b)		548,673		5,520		128,342
Exploration costs		8,631		4,576		11,177
Capitalized interest expenses		19,857		10,459		4,295
Transfers to Evaluated Properties		(40,621)		(30,899)		(44,511)
End of period balance	$	668,721	$	132,181	$	142,525
Accumulated depreciation, depletion and amortization
Beginning of period balance	$	1,756,018	$	1,478,355	$	1,420,612
Provision charged to expense		71,330		69,228		56,663
Write-down of oil and natural gas properties (a)		95,788		208,435		—
Sale of mineral interests		24,537		—		1,080
End of period balance	$	1,947,673	$	1,756,018	$	1,478,355

(a)

The Company uses the full cost method of accounting for its exploration and development activities. See the Company’s accounting policy about oil and natural gas properties in Note 2 for details on the full cost method of accounting.

(b)

See Note 3 in the Footnotes to the Financial Statements for additional information about the Company’s significant acquisitions.

(c)

Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest expenses and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The majority of these costs are primarily associated with the Company’s focus areas of its future development program and are expected to be evaluated over ten to fifteen years. The Company’s unevaluated property balance of $668,721 as of December 31, 2016, consisted of $123,345, $521,520 and $23,856 of costs attributable to our Monarch, WildHorse and Ranger operating areas, respectively.

Subsequent to December 31, 2016, and through February 22, 2017, the Company drilled four gross (3.4 net) horizontal wells and completed five gross (3.4 net) horizontal wells and had five gross (4.1 net) horizontal wells awaiting completion.

Depletion per unit-of-production, on a BOE basis, amounted to $12.81, $19.74 and $27.51 for the years ended December 31, 2016, 2015, and 2014, respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $6.88, $7.71, and $10.85 for the years ended December 31, 2016, 2015, and 2014, respectively.

Estimated Reserves

The Company’s proved oil and natural gas reserves at December 31, 2016, 2015 and 2014 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.

There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.

The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States:


	For the Year Ended December 31,
Proved developed and undeveloped reserves:	2016	2015	2014
Oil (MBbls):
Beginning of period	43,348	25,733	11,898
Revisions to previous estimates	(5,738)	(1,632)	(243)
Purchase of reserves in place	25,054	2,932	3,223
Sale of reserves in place	(1,718)	(23)	—
Extensions and discoveries	14,479	19,127	12,547
Production	(4,280)	(2,789)	(1,692)
End of period	71,145	43,348	25,733
Natural Gas (MMcf):
Beginning of period	65,537	42,548	17,751
Revisions to previous estimates	13,929	4,870	(215)
Purchase of reserves in place	36,474	2,915	8,591
Sale of reserves in place	(2,765)	(105)	—
Extensions and discoveries	17,194	19,621	18,641
Production	(7,758)	(4,312)	(2,220)
End of period	122,611	65,537	42,548


	For the Year Ended December 31,
Proved developed reserves:	2016	2015	2014
Oil (MBbls):
Beginning of period	22,257	14,006	5,960
End of period	32,920	22,257	14,006
Natural gas (MMcf):
Beginning of period	38,157	25,171	9,059
End of period	61,871	38,157	25,171
MBOE:
Beginning of period	28,617	18,201	7,470
End of period	43,232	28,617	18,201
Proved undeveloped reserves:
Oil (MBbls):
Beginning of period	21,091	11,727	5,938
End of period	38,225	21,091	11,727
Natural gas (MMcf):
Beginning of period	27,380	17,377	8,692
End of period	60,740	27,380	17,377
MBOE:
Beginning of period	25,654	14,623	7,387
End of period	48,348	25,654	14,623

Total Proved Reserves: The Company ended 2016 with estimated net proved reserves of 91,580 MBOE, representing a 69% increase over 2015 year-end estimated net proved reserves of 54,271 MBOE. The Company added 48,477 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 29 gross (20.9 net) wells. This increase was primarily offset by 11,168 MBOE related to divestitures, 2016 production and revisions primarily due to pricing.

The Company ended 2015 with estimated net proved reserves of 54,271 MBOE, representing a 65% increase over 2014 year-end estimated net proved reserves of 32,824 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, where it drilled a total of 36 gross (27.1 net) wells, and acquisitions made during 2015. This increase was primarily offset by 2015 production and revisions.

The Company ended 2014 with estimated net proved reserves of 32,824 MBOE, representing a 121% increase over 2013 year-end estimated net proved reserves of 14,857 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, where it drilled a total of 34 gross (28.7 net) wells, and acquisitions made during 2014. This increase was primarily offset by 2014 production and revisions.

Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories.

Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company’s PUDs increased 88% to 48,348 MBOE from 25,654 MBOE at December 31, 2016 and 2015, respectively. The Company added 17,482 MBOE to its PUDs, primarily from acquisitions in the Permian Basin, net of divestitures, and added 12,035 MBOE from the continued horizontal development of its Permian Basin properties, net of revisions. The increase in Permian Basin PUDs was partially offset by the reclassification of 6,823 MBOE, or 27%, included in the year-end 2015 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $43,415, net.

The Company’s PUDs increased 75% to 25,654 MBOE from 14,623 MBOE at December 31, 2015 and 2014, respectively. The Company added 13,774 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 2,742 MBOE, or 19%, included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $55,933, net.

The Company’s PUDs increased 98% to 14,623 MBOE from 7,387 MBOE at December 31, 2014 and 2013, respectively. The Company added 10,125 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 1,757 MBOE, or 24%, included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $34,619, net. Also offsetting the increase was the removal of 1,132 MBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development.

Standardized Measure

The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2016. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:



		2016		2015		2014
Average 12-month price, net of differentials, per Mcf of natural gas (a)	$	2.71	$	2.73	$	6.38
Average 12-month price, net of differentials, per barrel of oil (b)	$	40.03	$	47.25	$	86.30

(a)

Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties.

(b)

Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.

Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.


	Standardized Measure
	For the Year Ended December 31,
	2016		2015		2014
Future cash inflows	$	3,180,005	$	2,227,463	$	2,492,178
Future costs
Production		(974,667)		(827,555)		(873,469)
Development and net abandonment		(384,117)		(239,100)		(288,081)
Future net inflows before income taxes		1,821,221		1,160,808		1,330,628
Future income taxes		(1,602)		—		(164,490)
Future net cash flows		1,819,619		1,160,808		1,166,138
10% discount factor		(1,009,787)		(589,918)		(586,596)
Standardized measure of discounted future net cash flows	$	809,832	$	570,890	$	579,542


	Changes in Standardized Measure
	For the Year Ended December 31,
	2016		2015		2014
Standardized measure at the beginning of the period	$	570,890	$	579,542	$	283,946
Sales and transfers, net of production costs		(150,628)		(110,476)		(120,518)
Net change in sales and transfer prices, net of production costs		(103,136)		(286,660)		(156,066)
Net change due to purchases and sales of in place reserves		260,859		37,616		111,331
Extensions, discoveries, and improved recovery, net of future production and development costs incurred		180,228		184,469		299,192
Changes in future development cost		82,320		108,216		186,605
Revisions of quantity estimates		(35,938)		(12,625)		(7,673)
Accretion of discount		57,091		62,968		30,114
Net change in income taxes		16		35,407		(32,940)
Changes in production rates, timing and other		(51,870)		(27,567)		(14,449)
Aggregate change		238,942		(8,652)		295,596
Standardized measure at the end of period	$	809,832	$	570,890	$	579,542