Edgar Filing: CALLON PETROLEUM CO

Q2 - Form 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



	FORM 10-Q

☒Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For The Quarterly Period Ended June 30, 2015

☐Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ____________ to ____________

Commission File Number 001-14039

Callon Petroleum Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware

(State or Other Jurisdiction of

Incorporation or Organization)

64-0844345

(IRS Employer

Identification No.)

200 North Canal Street

Natchez, Mississippi

(Address of Principal Executive Offices)

39120

(Zip Code)

601-442-1601

(Registrant’s Telephone Number, Including Area Code)

Not Applicable

(Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report)

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes ☒No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes ☒No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):


Large accelerated filer	☐		Accelerated filer	☒

Non-accelerated filer	☐	(Do not check if smaller reporting company)	Smaller reporting company	☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes ☐No ☒

The Registrant had 66,279,074 shares of common stock outstanding as of July 31, 2015.

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Part I. Financial Information

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets	4

Consolidated Statements of Operations	5

Consolidated Statements of Cash Flows	6

Notes to Consolidated Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3. Quantitative and Qualitative Disclosures about Market Risk	25

Item 4. Controls and Procedures	26

Part II. Other Information

Item 1. Legal Proceedings	27

Item 1A. Risk Factors	27

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	27

Item 3. Defaults Upon Senior Securities	27

Item 4. Mine Safety Disclosures	27

Item 5. Other Information	27

Item 6. Exhibits	28

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DEFINITIONS

All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:

ARO: asset retirement obligation.

Bbl or Bbls: barrel or barrels of oil or natural gas liquids.

BOE: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.

BBtu: billion Btu.

BOE/d: BOE per day.

Btu: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

LIBOR: London Interbank Offered Rate.

LOE: lease operating expense.

MBbls: thousand barrels of oil.

MBOE: thousand BOE.

Mcf: thousand cubic feet of natural gas.

MMBtu: million Btu.

MMcf: million cubic feet of natural gas.

NGL or NGLs: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

NYMEX: New York Mercantile Exchange.

Oil: includes crude oil and condensate.

SEC: United States Securities and Exchange Commission.

GAAP: Generally Accepted Accounting Principles in the United States.

With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

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Part I. Financial Information

Item I. Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and per share values and share data)



	June 30, 2015		December 31, 2014
ASSETS		Unaudited
Current assets:
Cash and cash equivalents	$	2,028	$	968
Accounts receivable		34,499		30,198
Fair value of derivatives		6,889		27,850
Other current assets		1,525		1,441
Total current assets		44,941		60,457
Oil and natural gas properties, full cost accounting method:
Evaluated properties		2,207,999		2,077,985
Less accumulated depreciation, depletion and amortization		(1,514,036)		(1,478,355)
Net oil and natural gas properties		693,963		599,630
Unevaluated properties		131,121		142,525
Total oil and natural gas properties		825,084		742,155
Other property and equipment, net		7,874		7,118
Restricted investments		3,299		3,810
Deferred tax asset		46,497		44,688
Deferred financing costs		16,639		18,200
Other assets, net		658		342
Total assets	$	944,992	$	876,770
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	65,792	$	76,753
Accrued interest		5,974		5,993
Cash-settled restricted stock unit awards		8,172		3,856
Asset retirement obligations		872		4,747
Deferred tax liability		830		6,214
Fair value of derivatives		1,622		1,249
Total current liabilities		83,262		98,812
Senior secured revolving credit facility		75,000		35,000
Secured second lien term loan		300,000		300,000
Asset retirement obligations		3,249		1,927
Cash-settled restricted stock unit awards		3,086		7,175
Other long-term liabilities		219		121
Total liabilities		464,816		443,035
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively		16		16
Common stock, $0.01 par value, 110,000,000 shares authorized; 66,190,660 and 55,225,288 shares outstanding, respectively		662		552
Capital in excess of par value		591,604		526,162
Accumulated deficit		(112,106)		(92,995)
Total stockholders’ equity		480,176		433,735
Total liabilities and stockholders’ equity	$	944,992	$	876,770

The accompanying notes are an integral part of these consolidated financial statements.

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Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)



	Three Months Ended June 30,				Six Months Ended June 30,
		2015		2014		2015		2014
Operating revenues:
Oil sales	$	36,093	$	37,710	$	64,002	$	68,619
Natural gas sales		3,149		2,792		5,631		5,168
Total operating revenues		39,242		40,502		69,633		73,787
Operating expenses:
Lease operating expenses		6,575		4,363		13,534		8,593
Production taxes		2,952		2,265		5,217		4,182
Depreciation, depletion and amortization		17,587		11,982		35,691		22,520
General and administrative		5,763		9,639		17,865		20,446
Accretion expense		134		173		343		401
Rig termination fee		—		—		3,641		—
Gain on sale of other property and equipment		—		—		—		(1,080)
Total operating expenses		33,011		28,422		76,291		55,062
Income (loss) from operations		6,231		12,080		(6,658)		18,725
Other (income) expenses:
Interest expense		5,106		1,825		9,964		2,802
Gain on early extinguishment of debt		—		(3,205)		—		(3,205)
Loss on derivative contracts		8,249		4,685		5,820		7,198
Other income		(41)		(93)		(85)		(142)
Total other expenses		13,314		3,212		15,699		6,653
Income (loss) before income taxes		(7,083)		8,868		(22,357)		12,072
Income tax expense (benefit)		(2,116)		4,128		(7,193)		5,469
Net income (loss)		(4,967)		4,740		(15,164)		6,603
Preferred stock dividends		(1,973)		(1,973)		(3,947)		(3,947)
Income (loss) available to common stockholders	$	(6,940)	$	2,767	$	(19,111)	$	2,656
Income (loss) per common share:
Basic	$	(0.11)	$	0.07	$	(0.31)	$	0.07
Diluted	$	(0.11)	$	0.07	$	(0.31)	$	0.06
Shares used in computing income (loss) per common share:
Basic		66,038		40,606		61,759		40,467
Diluted		66,038		41,605		61,759		41,652

The accompanying notes are an integral part of these consolidated financial statements.

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Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)


	Six Months Ended June 30,
		2015		2014
Cash flows from operating activities:
Net income (loss)	$	(15,164)	$	6,603
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization		36,557		22,976
Accretion expense		343		401
Amortization of non-cash debt related items		1,561		298
Amortization of deferred credit		—		(433)
Deferred income tax (benefit) expense		(7,193)		5,469
Net loss on derivatives, net of settlements		21,129		4,677
Gain on sale of other property and equipment		—		(1,080)
Non-cash gain for early debt extinguishment		—		(3,205)
Non-cash expense related to equity share-based awards		(668)		(36)
Change in the fair value of liability share-based awards		4,695		8,070
Payments to settle asset retirement obligations		(1,905)		(1,469)
Changes in current assets and liabilities:
Accounts receivable		(6,946)		(5,268)
Other current assets		(85)		265
Current liabilities		5,549		2,014
Payments to settle vested liability share-based awards related to early retirements		(3,538)		(1,417)
Payments to settle vested liability share-based awards		(3,925)		(2,052)
Change in other long-term liabilities		100		—
Change in other assets, net		(528)		(216)
Net cash provided by operating activities		29,982		35,597
Cash flows from investing activities:
Capital expenditures		(130,847)		(127,219)
Proceeds from sales of mineral interests and equipment		326		2,267
Net cash used in investing activities		(130,521)		(124,952)
Cash flows from financing activities:
Borrowings on credit facility		103,000		150,000
Payments on credit facility		(63,000)		(55,610)
Payment of deferred financing costs		—		(2,928)
Issuance of common stock		65,546		—
Payment of preferred stock dividends		(3,947)		(3,947)
Net cash provided by financing activities		101,599		87,515
Net change in cash and cash equivalents		1,060		(1,840)
Balance, beginning of period		968		3,012
Balance, end of period	$	2,028	$	1,172

The accompanying notes are an integral part of these consolidated financial statements.

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per unit data)

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Description of Business and Basis of Presentation	6.	Fair Value Measurements
2.	Acquisitions	7.	Asset Retirement Obligations
3.	Earnings Per Share	8.	Equity Transactions
4.	Borrowings	9.	Other
5.	Derivative Instruments and Hedging Activities

Note 1 - Description of Business and Basis of Presentation

Description of business

Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

Callon is focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas, and more specifically, the Midland Basin. The Company’s operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through acreage purchases, joint ventures and asset swaps.

Basis of presentation

Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data.

The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc.

These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The balance sheet at December 31, 2014 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2015.

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

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Recently issued accounting policies

In April 2015, the Financial Accounting Standards Board issued accounting standards update (“ASU”) No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The standard requires that the costs for issuing debt should appear on the balance sheet as direct reduction from the debt’s value. The guidance in ASU No. 2015-03 is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.

Note 2 – Acquisitions

On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Ector and Martin Counties, Texas (the “Central Midland Basin Acquisition”) for an aggregate cash purchase price of $210,205. The Company assumed operatorship of the properties on November 1, 2014, and acquired a 62% working interest (46.5% net revenue interest) in the Central Midland Basin Acquisition. The aggregate cash purchase price was funded with a combination of the net proceeds from an equity offering of $122,450 and a portion of the net proceeds from borrowings under a secured second lien term loan.

The Central Midland Basin Acquisition was accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed. The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired:


Oil and natural gas properties	$	91,895
Unevaluated oil and natural gas properties		118,450
Asset retirement obligations		(140)
Net assets acquired	$	210,205

The following unaudited summary pro forma financial information for the three and six months ended June 30, 2014 has been presented for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Central Midland Basin Acquisition had occurred as presented, or to project the Company’s results of operations for any future periods. The pro forma financial information was prepared assuming the Central Midland Basin Acquisition occurred as of January 1, 2013. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.


	Three Months Ended		Six Months Ended
	June 30, 2014		June 30, 2014
Revenues	$	50,819	$	94,003
Income from operations		17,941		30,298
Income available to common stockholders		4,752		5,543

Net income per common share:
Basic	$	0.09	$	0.10
Diluted	$	0.08	$	0.10

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

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Note 3 - Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share:


(share amounts in thousands)	Three Months Ended June 30,				Six Months Ended June 30,
		2015		2014		2015		2014
Net income (loss)	$	(4,967)	$	4,740	$	(15,164)	$	6,603
Preferred stock dividends		(1,973)		(1,973)		(3,947)		(3,947)
Income (loss) available to common stockholders	$	(6,940)	$	2,767	$	(19,111)	$	2,656

Weighted average shares outstanding		66,038		40,606		61,759		40,467
Dilutive impact of restricted stock		—		999		—		1,185
Weighted average shares outstanding for diluted loss per share		66,038		41,605		61,759		41,652

Basic income (loss) per share	$	(0.11)	$	0.07	$	(0.31)	$	0.07
Diluted income (loss) per share	$	(0.11)	$	0.07	$	(0.31)	$	0.06

Stock options (a)		15		30		15		30
Restricted stock (a)		284		—		284		—

(a)

Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Note 4 – Borrowings

The Company’s borrowings consisted of the following at:


	June 30, 2015		December 31, 2014
Principal components:
Senior secured revolving credit facility	$	75,000	$	35,000
Secured second lien term loan		300,000		300,000
Total carrying value of borrowings	$	375,000	$	335,000

Senior secured revolving credit facility (the “Credit Facility”)

On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019. JPMorgan Chase Bank, N.A. is Administrative Agent, and participating lenders include Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A., SunTrust Bank and Royal Bank of Canada. The total notional amount available under the Credit Facility is $500,000. Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. As of June 30, 2015, the Credit Facility’s borrowing base was $250,000. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.

As of June 30, 2015, the balance outstanding on the Credit Facility was $75,000 with a weighted-average interest rate of 2.19%, calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base.

Secured second lien term loan (the “Term Loan”)

On October 8, 2014, the Company entered into the Term Loan with an aggregate amount of up to $300,000 and a maturity date of October 8, 2021. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. The Term Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 2015, (ii) 101% if the prepayment event occurs on or after October 8, 2015 but before October 8, 2016, and (iii) 100% for prepayments made on or after October 8, 2016. The Term Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. As of June 30, 2015, the balance outstanding on

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

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the Term Loan was $300,000 with an interest rate of 8.5%, calculated at a rate of LIBOR (subject to a floor rate of 1.0%) plus 7.5% per annum. The Company can elect a LIBOR rate based on various tenors, and is currently incurring interest based on an underlying three-month LIBOR rate, which was last elected in July 2015.

Restrictive covenants

The Company’s Credit Facility and Term Loan contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at June 30, 2015.

Note 5 - Derivative Instruments and Hedging Activities

Objectives and strategies for using derivative instruments

The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps, puts, calls and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.

Counterparty risk and offsetting

The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 6 for additional information regarding fair value.

The Company executes commodity derivative contracts under master agreements that have netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.

Financial statement presentation and settlements

Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 6 for additional information regarding fair value.

Derivatives not designated as hedging instruments

The Company records its derivative contracts at fair value in the consolidated balance sheet and records changes in fair value as a gain or loss on derivative contracts in the consolidated statement of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statement of operations.

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

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The following table reflects the fair value of the Company’s derivative instruments for the periods presented:


	Balance Sheet Presentation		Asset Fair Value				Liability Fair Value				Net Derivative Fair Value
Commodity	Classification	Line Description	06/30/2015		12/31/2014		06/30/2015		12/31/2014		06/30/2015		12/31/2014
Natural gas	Current	Fair value of derivatives	$	671	$	1,262	$	(1)	$	(7)	$	670	$	1,255
Oil	Current	Fair value of derivatives		6,218		26,588		(1,621)		(1,242)		4,597		25,346
Oil	Non-current	Other assets, net		205		—		—		—		205		—
	Totals		$	7,094	$	27,850	$	(1,622)	$	(1,249)	$	5,472	$	26,601

As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:


		June 30, 2015
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	8,370	$	(1,481)	$	6,889
Long-term assets: Other assets, net		205		—		205
Current liabilities: Fair value of derivatives	$	(3,103)	$	1,481	$	(1,622)


		December 31, 2014
	Presented without				As Presented with
	Effects of Netting		Effects of Netting		Effects of Netting
Current assets: Fair value of derivatives	$	27,850	$	—	$	27,850
Current liabilities: Fair value of derivatives	$	(1,249)	$	—	$	(1,249)

For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:


	Three Months Ended June 30,				Six Months Ended June 30,
		2015		2014		2015		2014
Oil derivatives
Net gain (loss) on settlements	$	4,511	$	(1,569)	$	14,464	$	(2,341)
Net loss on fair value adjustments		(12,755)		(3,097)		(20,544)		(4,546)
Total loss	$	(8,244)	$	(4,666)	$	(6,080)	$	(6,887)

Natural gas derivatives
Net gain (loss) on settlements	$	454	$	(77)	$	845	$	(179)
Net gain (loss) on fair value adjustments		(459)		58		(585)		(132)
Total gain (loss)	$	(5)	$	(19)	$	260	$	(311)

Total loss on derivative contracts	$	(8,249)	$	(4,685)	$	(5,820)	$	(7,198)

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

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Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of June 30, 2015:


	For the Three Months Ended
	September 30,		December 31,		March 31,		June 30,		September 30,		December 31,
Oil contracts	2015		2015		2016		2016		2016		2016
Swap contracts (NYMEX):
Total volume (MBbls)		520		442		91		91		92		92
Weighted average price per Bbl	$	67.22	$	64.93	$	63.50	$	63.50	$	63.50	$	63.50
Swap contracts (Midland basis
differential):
Volume (MBbls)		382		327		—		—		—		—
Weighted average price per Bbl	$	(2.39)	$	(2.38)	$	—	$	—	$	—	$	—
Collar contracts combined with
short puts (three-way collar):
Volume (MBbls)		—		—		91		91		92		92
Weighted average price per Bbl
Ceiling (short call)	$	—	$	—	$	70.00	$	70.00	$	70.00	$	70.00
Floor (long put)	$	—	$	—	$	60.00	$	60.00	$	60.00	$	60.00
Short put	$	—	$	—	$	45.00	$	45.00	$	45.00	$	45.00


	For the Three Months Ended
	September 30,		December 31,		March 31,		June 30,		September 30,		December 31,
Natural gas contracts	2015		2015		2016		2016		2016		2016
Collar contracts combined with
short puts (three-way collar):
Volume (BBtu)		207		161		—		—		—		—
Weighted average price per
MMBtu
Ceiling (short call)	$	4.32	$	4.32	$	—	$	—	$	—	$	—
Floor (long put)	$	3.85	$	3.85	$	—	$	—	$	—	$	—
Short put	$	3.25	$	3.25	$	—	$	—	$	—	$	—
Swap contracts:
Total volume (BBtu)		219		228		—		—		—		—
Weighted average price per
MMBtu	$	3.98	$	3.96	$	—	$	—	$	—	$	—
Short call contracts:
Short call volume (BBtu)		110		111		—		—		—		—
Short call price per MMBtu	$	5.00	$	5.00	$	—	$	—	$	—	$	—

Note 6 - Fair Value Measurements

The fair value hierarchy included in GAAP gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.

Fair Value of Financial Instruments

Cash, cash equivalents, restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.

Debt. The Company’s debt is recorded at the carrying amount in the consolidated balance sheet. The carrying amount of floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates.

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

Table of Contents

Assets and liabilities measured at fair value on a recurring basis

Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value:

Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 5 for additional information regarding the Company’s derivative instruments.

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:


Balance Sheet Presentation as of June 30, 2015	Classification		Level 1		Level 2		Level 3		Total
Fair value of derivatives	Current assets	$	—	$	6,889	$	—	$	6,889
Other assets, net	Long-term assets		—		205		—		205
Fair value of derivatives	Current liabilities		—		(1,622)		—		(1,622)
Total net assets		$	—	$	5,472	$	—	$	5,472

Balance Sheet Presentation as of December 31, 2014	Classification		Level 1		Level 2		Level 3		Total
Fair value of derivatives	Current assets	$	—	$	27,850	$	—	$	27,850
Fair value of derivatives	Current liabilities		—		(1,249)		—		(1,249)
Total net assets		$	—	$	26,601	$	—	$	26,601

Note 7 - Asset Retirement Obligations

The table below summarizes the Company’s asset retirement obligations activity for the six months ended June 30, 2015:


Asset retirement obligations at January 1, 2015	$	6,674
Accretion expense