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Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended June 30, 2013

 

or

 

o         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: 001-36026

 

ATHLON ENERGY INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

46-2549833

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

420 Throckmorton Street, Suite 1200, Fort Worth,

Texas

 

76102

(Address of principal executive offices)

 

(Zip Code)

 

(817) 984-8200

(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 the 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 o  No x

 

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o  No o

 

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer x

(Do not check if a smaller reporting company)

 

Smaller reporting company o

 

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

 

As of August 13, 2013, we had 82,129,089 outstanding shares of common stock, $0.01 par value, excluding Athlon Holdings LP units exchangeable for 1,855,563 shares of our common stock.

 

 

 



Table of Contents

 

ATHLON ENERGY INC.

 

INDEX

 

 

 

 

 

Page

PART I. FINANCIAL INFORMATION

 

 

 

 

 

 

 

Item 1.

 

Financial Statements

 

 

 

 

 

 

 

 

 

Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012

 

1

 

 

 

 

 

 

 

Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012

 

2

 

 

 

 

 

 

 

Consolidated Statement of Changes in Equity for the six months ended June 30, 2013

 

3

 

 

 

 

 

 

 

Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012

 

4

 

 

 

 

 

 

 

Notes to Consolidated Financial Statements

 

5

 

 

 

 

 

Item 2.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

17

 

 

 

 

 

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

34

 

 

 

 

 

Item 4.

 

Controls and Procedures

 

36

 

 

 

PART II. OTHER INFORMATION

 

 

 

 

 

 

 

Item 1.

 

Legal Proceedings

 

37

 

 

 

 

 

Item 1A.

 

Risk Factors

 

37

 

 

 

 

 

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

37

 

 

 

 

 

Item 6.

 

Exhibits

 

37

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

 

Certain information included in this Quarterly Report on Form 10-Q (the “Report”) and our other materials filed with the United States Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements.  These forward-looking statements give our current expectations or forecasts of future events.  Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts.  These statements may include words such as “may”, “will”, “could”, “anticipate”, “estimate”, “expect”, “project”, “intend”, “plan”, “believe”, “should”, “predict”, “potential”, “pursue”, “target”, “continue”, and other words and terms of similar meaning.  You are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this Report.  Our actual results may differ significantly from the results discussed in the forward-looking statements.  Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in “Risk Factors” in our final prospectus dated August 1, 2013 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933 on August 5, 2013.  If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected.  We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

 

i



Table of Contents

 

GLOSSARY

 

The following are abbreviations and definitions of certain terms used in this Report:

 

·                  Basin.  A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

·                  Bbl.  One stock tank barrel, of 42 U.S. gallons liquid volume, used in reference to crude oil, condensate, or natural gas liquids.

·                  Bbl/D.  One Bbl per day.

·                  BOE.  One barrel of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

·                  BOE/D.  One barrel of oil equivalent per day.

·                  Completion.  The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

·                  Condensate.  A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

·                  Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.

·                  Development capital.  Expenditures to obtain access to proved reserves and to construct facilities for producing, treating, and storing hydrocarbons.

·                  Dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

·                  Economically producible.  A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).

·                  Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

·                  FASB.  Financial Accounting Standards Board.

·                  Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.  The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.  For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

·                  Formation.  A layer of rock which has distinct characteristics that differ from nearby rock.

·                  GAAP.  Accounting principles generally accepted in the United States.

·                  Gross acres or Gross wells.  The total acres or wells, as the case may be, in which an entity owns a working interest.

·                  Holdings.  Athlon Holdings LP, our accounting predecessor.

·                  Horizontal drilling.  A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

·                  Infill wells.  Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

·                  Lease operating expense (“LOE”).  All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest.  Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

·                  LIBOR.  London Interbank Offered Rate.

·                  MBbl.  One thousand barrels of crude oil, condensate, or NGLs.

·                  MBOE.  One thousand barrels of oil equivalent.

·                  Mcf.  One thousand cubic feet of natural gas.

·                  MMBOE.  One million barrels of oil equivalent.

·                  MMcf.  One million cubic feet of natural gas.

·                  MMcf/D.  One million cubic feet of natural gas per day.

·                  MMcfe/D.  One million cubic feet of natural gas equivalent per day.

·                  Natural gas liquids (“NGLs”).  The combination of ethane, propane, butane, isobutane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

·                  Net acres or Net wells.  The percentage of total acres or wells, as the case may be, an owner has out of a particular number of gross acres or wells.  For example, an owner who has 50% interest in 100 gross acres owns 50 net acres.

·                 NYMEX.  The New York Mercantile Exchange.

·                  Operator.  The entity responsible for the exploration, development, and production of a well or lease.

 

ii



Table of Contents

 

·                  Production margin.  Total wellhead revenues less total production costs.

·                  Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

·                  Proved developed reserves.  Proved reserves that can be expected to be recovered:

i.                  Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or

ii.               Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

·                  Proved reserves.  Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence, the project within a reasonable time.  For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

·                  Proved undeveloped reserves (PUDs).  Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

·                  Reasonable certainty.  A high degree of confidence.  For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

·                  Recompletion.  The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

·                  Reliable technology.  A grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

·                  Reserves.  Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development prospects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.

·                  Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.

·                  Spacing.  The distance between wells producing from the same reservoir.  Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

·                  Stacked pay.  Multiple geological zones that potentially contain hydrocarbons and are arranged in a vertical stack.

·                  Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

·                  Wellbore.  The hole drilled by the bit that is equipped for oil or gas production on a completed well.  Also called well or borehole.

·                  Working interest.  The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals.  The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

·                  Workover.  Operations on a producing well to restore or increase production.

·                  WTI.  West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

 

iii



Table of Contents

 

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

ATHLON ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and par value amounts)

 

 

 

June 30,

 

December 31,

 

 

 

2013

 

2012

 

 

 

(unaudited)

 

 

 

ASSETS

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

2,547

 

$

8,871

 

Accounts receivable

 

37,124

 

24,501

 

Derivatives

 

3,022

 

2,246

 

Inventory

 

999

 

1,022

 

Other

 

600

 

2,486

 

Total current assets

 

44,292

 

39,126

 

 

 

 

 

 

 

Properties and equipment, at cost - full cost method:

 

 

 

 

 

Proved properties, including wells and related equipment

 

971,092

 

788,571

 

Unproved properties

 

95,523

 

89,860

 

Accumulated depletion, depreciation, and amortization

 

(112,131

)

(73,824

)

 

 

954,484

 

804,607

 

 

 

 

 

 

 

Derivatives

 

7,392

 

2,854

 

Debt issuance costs

 

15,148

 

4,418

 

Other

 

2,837

 

1,293

 

Total assets

 

$

1,024,153

 

$

852,298

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable:

 

 

 

 

 

Trade

 

$

369

 

$

3,170

 

Affiliate

 

214

 

935

 

Accrued liabilities:

 

 

 

 

 

Lease operating

 

4,761

 

3,858

 

Production, severance, and ad valorem taxes

 

3,762

 

1,307

 

Development capital

 

49,345

 

39,483

 

Interest

 

7,732

 

834

 

Derivatives

 

299

 

592

 

Revenue payable

 

15,555

 

9,330

 

Deferred taxes

 

2,777

 

58

 

Other

 

2,412

 

1,808

 

Total current liabilities

 

87,226

 

61,375

 

 

 

 

 

 

 

Derivatives

 

 

519

 

Asset retirement obligations, net of current portion

 

5,877

 

5,049

 

Long-term debt

 

543,500

 

362,000

 

Deferred taxes

 

77,696

 

2,340

 

Other

 

119

 

138

 

Total liabilities

 

714,418

 

431,421

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

Equity:

 

 

 

 

 

Partners’ equity

 

 

420,877

 

Preferred stock, $.01 par value, 50,000,000 shares authorized, none issued and outstanding

 

 

 

Common stock, $.01 par value, 500,000,000 shares authorized, 66,339,615 and none issued and outstanding, respectively

 

663

 

 

Additional paid-in capital

 

278,450

 

 

Retained earnings

 

20,362

 

 

Total stockholders’ equity

 

299,475

 

 

Noncontrolling interest

 

10,260

 

 

Total equity

 

309,735

 

420,877

 

Total liabilities and equity

 

$

1,024,153

 

$

852,298

 

 

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

 

1



Table of Contents

 

ATHLON ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

(unaudited)

 

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Revenues:

 

 

 

 

 

 

 

 

 

Oil

 

$

54,609

 

$

29,617

 

$

100,268

 

$

57,050

 

Natural gas

 

4,363

 

1,492

 

7,730

 

2,940

 

Natural gas liquids

 

6,193

 

4,682

 

11,913

 

9,033

 

Total revenues

 

65,165

 

35,791

 

119,911

 

69,023

 

 

 

 

 

 

 

 

 

 

 

Expenses:

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

Lease operating

 

7,775

 

5,942

 

15,012

 

10,641

 

Production, severance, and ad valorem taxes

 

4,247

 

2,461

 

7,941

 

4,811

 

Depletion, depreciation, and amortization

 

20,358

 

13,065

 

38,411

 

22,679

 

General and administrative

 

3,659

 

2,481

 

6,998

 

5,078

 

Derivative fair value gain

 

(12,555

)

(46,569

)

(5,706

)

(23,858

)

Other operating

 

227

 

116

 

421

 

246

 

Total expenses

 

23,711

 

(22,504

)

63,077

 

19,597

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

41,454

 

58,295

 

56,834

 

49,426

 

Interest expense

 

12,082

 

1,705

 

16,556

 

3,200

 

 

 

 

 

 

 

 

 

 

 

Income before income taxes

 

29,372

 

56,590

 

40,278

 

46,226

 

Income tax provision

 

4,844

 

1,986

 

4,871

 

1,622

 

 

 

 

 

 

 

 

 

 

 

Consolidated net income

 

24,528

 

54,604

 

35,407

 

44,604

 

Less: net income attributable to noncontrolling interest

 

831

 

 

831

 

 

Net income attributable to stockholders

 

$

23,697

 

$

54,604

 

$

34,576

 

$

44,604

 

 

 

 

 

 

 

 

 

 

 

Net income per common share:

 

 

 

 

 

 

 

 

 

Basic

 

$

0.36

 

$

0.82

 

$

0.52

 

$

0.67

 

Diluted

 

$

0.36

 

$

0.80

 

$

0.52

 

$

0.65

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

 

Basic

 

66,340

 

66,340

 

66,340

 

66,340

 

Diluted

 

68,196

 

68,196

 

68,196

 

68,196

 

 

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

 

2



Table of Contents

 

ATHLON ENERGY INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(in thousands)

(unaudited)

 

 

 

 

 

Athlon Stockholders

 

 

 

 

 

 

 

 

 

Issued

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shares of

 

 

 

Additional

 

 

 

Total

 

 

 

 

 

 

 

Partners’

 

Common

 

Common

 

Paid-in

 

Retained

 

Stockholders’

 

Noncontrolling

 

Total

 

 

 

Equity

 

Stock

 

Stock

 

Capital

 

Earnings

 

Equity

 

Interest

 

Equity

 

Balance at December 31, 2012

 

$

420,877

 

 

$

 

$

 

$

 

$

 

$

 

$

420,877

 

Capital contributions

 

1,500

 

 

 

 

 

 

 

1,500

 

Equity-based compensation prior to corporate reorganization

 

89

 

 

 

 

 

 

 

89

 

Net income prior to corporate reorganization

 

14,214

 

 

 

 

 

 

 

14,214

 

Distributions to Athlon Holdings LP Class A limited partners

 

(75,000

)

 

 

 

 

 

 

(75,000

)

Common stock issued in corporate reorganization

 

(361,680

)

66,340

 

663

 

351,588

 

 

352,251

 

9,429

 

 

Tax impact of corporate reorganization

 

 

 

 

(73,204

)

 

(73,204

)

 

(73,204

)

Equity-based compensation subsequent to corporate reorganization

 

 

 

 

66

 

 

66

 

 

66

 

Consolidated net income subsequent to corporate reorganization

 

 

 

 

 

20,362

 

20,362

 

831

 

21,193

 

Balance at June 30, 2013

 

$

 

66,340

 

$

663

 

$

278,450

 

$

20,362

 

$

299,475

 

$

10,260

 

$

309,735

 

 

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

 

3



Table of Contents

 

ATHLON ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

 

 

 

Six months ended June 30,

 

 

 

2013

 

2012

 

Cash flows from operating activities:

 

 

 

 

 

Consolidated net income

 

$

35,407

 

$

44,604

 

Adjustments to reconcile consolidated net income to net cash provided by operating activities:

 

 

 

 

 

Depletion, depreciation, and amortization

 

38,411

 

22,679

 

Deferred taxes

 

4,871

 

1,622

 

Non-cash derivative gain

 

(6,127

)

(26,424

)

Equity-based compensation

 

113

 

91

 

Other

 

3,979

 

550

 

Changes in operating assets and liabilities, net of effects from acquisitions:

 

 

 

 

 

Accounts receivable

 

(12,623

)

(3,012

)

Other current assets

 

424

 

(348

)

Accounts payable

 

(2,503

)

1,714

 

Revenue payable

 

5,723

 

1,251

 

Other current liabilities

 

11,549

 

(552

)

Net cash provided by operating activities

 

79,224

 

42,175

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Acquisitions of oil and natural gas properties

 

(16,482

)

(3,142

)

Development of oil and natural gas properties

 

(161,514

)

(121,968

)

Other

 

(336

)

(189

)

Net cash used in investing activities

 

(178,332

)

(125,299

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Proceeds from long-term debt, net of issuance costs

 

594,647

 

275,944

 

Payments on long-term debt

 

(427,426

)

(220,000

)

Distributions to Athlon Holdings LP Class A limited partners

 

(75,000

)

 

Other

 

563

 

166

 

Net cash provided by financing activities

 

92,784

 

56,110

 

 

 

 

 

 

 

Decrease in cash and cash equivalents

 

(6,324

)

(27,014

)

Cash and cash equivalents, beginning of period

 

8,871

 

32,030

 

Cash and cash equivalents, end of period

 

$

2,547

 

$

5,016

 

 

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

 

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Table of Contents

 

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

 

Note 1.   Formation of the Company and Description of Business

 

Athlon Energy Inc. (together with its subsidiaries, “Athlon”), a Delaware corporation, was formed on April 1, 2013 and is an independent exploration and production company focused on the acquisition, development, and exploitation of unconventional oil and liquids-rich natural gas reserves in the Permian Basin.

 

On April 26, 2013, Athlon Holdings LP (“Holdings”), a Delaware limited partnership, underwent a corporate reorganization and as a result, Holdings became a majority-owned subsidiary of Athlon.  Holdings is considered Athlon’s accounting predecessor.  Athlon operates and controls all of the business and affairs of Holdings and consolidates its financial results.  Holdings is not subject to federal income taxes.  On the date of the corporate reorganization, a corresponding “first day” tax expense of approximately $73.2 million was recorded to establish a net deferred tax liability for differences between the tax and book basis of Athlon’s assets and liabilities.  The offset of the deferred tax liability was recorded to additional paid-in capital.

 

Prior to the corporate reorganization, Holdings was a party to a limited partnership agreement with its management group and Apollo Athlon Holdings LLC (“Apollo”), which is an affiliate of Apollo Global Management, LLC.  Prior to the corporate reorganization, Apollo Investment Fund VII, L.P. and its parallel funds (the “Apollo Funds”), members of Holdings’ management team, and certain employees owned all of the Class A limited partner interests in Holdings and members of Holdings’ management team and certain employees owned all of the Class B limited partner interests in Holdings.

 

In the corporate reorganization, the Apollo Funds entered into a number of distribution and contribution transactions pursuant to which the Apollo Funds exchanged their Class A limited partner interests in Holdings for common stock of Athlon.  The remaining holders of Class A limited partner interests in Holdings have not exchanged their interests in the reorganization transactions.  In addition, the holders of the Class B limited partner interests in Holdings exchanged their interests for common stock of Athlon subject to the same conditions and vesting terms.

 

Initial Public Offering

 

On August 7, 2013, Athlon completed its initial public offering (“IPO”) of 15,789,474 shares of its common stock at $20.00 per share and received net proceeds of approximately $293.4 million, after deducting underwriting discounts and commissions and estimated offering expenses.  Upon closing of the IPO, the limited partnership agreement of Holdings was amended and restated to, among other things, modify Holdings’ capital structure by replacing its different classes of interests with a single new class of units, the “New Holdings Units”.  The members of Holdings’ management team and certain employees that held Class A limited partner interests now own 1,855,563 New Holdings Units and entered into an exchange agreement under which (subject to the terms of the exchange agreement) they have the right to exchange their New Holdings Units for shares of common stock of Athlon on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends, and reclassifications.  All other New Holdings Units are held by Athlon.  Athlon used the net proceeds from the IPO to purchase New Holdings Units from Holdings.  Holdings used the proceeds it received as a result of Athlon’s purchase of New Holdings Units (i) to reduce outstanding borrowings under its credit agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes.

 

Note 2.   Basis of Presentation

 

Athlon’s consolidated financial statements include the accounts of its wholly owned and majority-owned subsidiaries.  All material intercompany balances and transactions have been eliminated in consolidation.

 

In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, Athlon’s financial position as of June 30, 2013, results of operations for the three and six months ended June 30, 2013 and 2012, and cash flows for the six months ended June 30, 2013 and 2012.  All adjustments are of a normal recurring nature.  These interim results are not necessarily indicative of results for an entire year.

 

5



Table of Contents

 

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

Certain amounts and disclosures have been condensed and omitted from the unaudited consolidated financial statements pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”).  Therefore, these unaudited consolidated financial statements should be read in conjunction with Holdings’ audited consolidated financial statements and related notes thereto included in Athlon’s final prospectus dated August 1, 2013 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933 on August 5, 2013.

 

Income Taxes

 

Athlon accounts for income taxes using the asset and liability method.  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax laws and rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

 

Athlon periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses.  In making this determination, Athlon considers all available positive and negative evidence and makes certain assumptions.  Athlon considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years.  Athlon believes it is more likely than not that certain net operating losses can be carried forward and utilized.

 

In April 2013, Athlon had a corporate reorganization to effectuate its IPO.  Holdings, Athlon’s accounting predecessor, is a partnership not subject to federal income tax.  Pursuant to the steps of the corporate reorganization, certain Class A limited partners and the Class B limited partners of Holdings exchanged their interests for shares of Athlon’s common stock.  Athlon’s operations are now subject to federal income tax.  The tax implications of the corporate reorganization and the tax impact of the conversion to operating as a taxable entity have been reflected in the accompanying consolidated financial statements.

 

Noncontrolling Interest

 

As of June 30, 2013, management and employees owned approximately 3.2% of Holdings.  Athlon owns 100% of Athlon Holdings GP LLC, which is Holdings’ general partner.  Considering the presumption of control, Athlon has fully consolidated the financial position, results of operations, and cash flows of Holdings.

 

As presented in the accompanying Consolidated Balance Sheets, “Noncontrolling interest” as of June 30, 2013 of approximately $10.3 million represents management and employees’ 1,855,563 New Holdings Units that are exchangeable for shares of Athlon’s common stock on a one-for-one basis.  As presented in the accompanying Consolidated Statements of Operations, “Net income attributable to noncontrolling interest” for each of the three and six months ended June 30, 2013 of approximately $0.8 million represents the net income of Holdings attributable to management and employees since April 26, 2013.

 

New Accounting Pronouncements

 

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities” and in January 2013 issued ASU 2013-01, “Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities”.  These ASUs created new disclosure requirements regarding the nature of an entity’s rights of setoff and related arrangements associated with its derivative instruments, repurchase agreements, and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements are required, irrespective of whether the entity has elected to offset those instruments in the statement of financial position. These ASUs were effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs did not impact Athlon’s financial position, results of operations, or liquidity.

 

No other new accounting pronouncements issued or effective from January 1, 2013 through the date of this Report, had or are expected to have a material impact on Athlon’s unaudited consolidated financial statements.

 

6



Table of Contents

 

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

Note 3. Proved Properties

 

Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:

 

 

 

June 30,

 

December 31,

 

 

 

2013

 

2012

 

 

 

(in thousands)

 

Proved leasehold costs

 

$

408,791

 

$

376,271

 

Wells and related equipment - Completed

 

532,259

 

379,036

 

Wells and related equipment - In process

 

30,042

 

33,264

 

Total proved properties

 

$

971,092

 

$

788,571

 

 

Note 4.  Fair Value Measurements

 

The book values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments.  The book value of the credit agreement approximates fair value as the interest rate is variable.  Athlon considers debt with variable interest rates to have a fair value equal to its carrying value (“Level 1” input).  Commodity derivative contracts are marked-to-market each quarter and are thus stated at fair value in the accompanying Consolidated Balance Sheets.  As of June 30, 2013, the fair value of the senior notes was approximately $497.6 million using open market quotes (“Level 1” input).

 

Derivative Policy

 

Athlon uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil production.  These arrangements are structured to reduce Athlon’s exposure to commodity price decreases, but they can also limit the benefit Athlon might otherwise receive from commodity price increases.  Athlon’s risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions, most of which are lenders underwriting the Holdings Credit Agreement.

 

Athlon applies the provisions of the “Derivatives and Hedging” topic of the Accounting Standards Codification, which requires each derivative instrument to be recorded in the accompanying Consolidated Balance Sheets at fair value.  If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings.  Athlon elected not to designate its current portfolio of commodity derivative contracts as hedges for accounting purposes.  Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in “Derivative fair value gain” in the accompanying Consolidated Statements of Operations.

 

Athlon enters into commodity derivative contracts for the purpose of economically fixing the price of its anticipated oil production even though Athlon does not designate the derivatives as hedges for accounting purposes.  Athlon classifies cash flows related to derivative contracts based on the nature and purpose of the derivative.  As the derivative cash flows are considered an integral part of Athlon’s oil and natural gas operations, they are classified as cash flows from operating activities in the accompanying Consolidated Statements of Cash Flows.

 

Commodity Derivative Contracts

 

Commodity prices are often subject to significant volatility due to many factors that are beyond Athlon’s control, including but not limited to: prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters.  Athlon manages oil price risk with swaps, puts, and collars.  Swaps provide a fixed price for a notional amount of sales volumes.  Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.  This participation is limited by a ceiling price specified in the contract.

 

7



Table of Contents

 

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

The following table summarizes Athlon’s open commodity derivative contracts as of June 30, 2013:

 

 

 

Average

 

Weighted -

 

Average

 

Weighted -

 

Average

 

Weighted -

 

Asset

 

 

 

Daily

 

Average

 

Daily

 

Average

 

Daily

 

Average

 

(Liability)

 

 

 

Floor

 

Floor

 

Cap

 

Cap

 

Swap

 

Swap

 

Fair Market

 

Period

 

Volume

 

Price

 

Volume

 

Price

 

Volume

 

Price

 

Value

 

 

 

(Bbl)

 

(per Bbl)

 

(Bbl)

 

(per Bbl)

 

(Bbl)

 

(per Bbl)

 

(in thousands)

 

July - Dec. 2013

 

150

 

$

75.00

 

150

 

$

105.95

 

6,750

(a)

$

94.93

 

$

(208

)

2014

 

 

 

 

 

7,950

 

92.67

 

7,711

 

2015

 

 

 

 

 

1,300

 

93.18

 

3,536

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

11,039

 

 


(a)         Includes 6,500 Bbls/D at $94.85 per Bbl for the third quarter of 2013 and 7,000 Bbls/D at $95.01 per Bbl for the fourth quarter of 2013.

 

Athlon is also a party to Midland-Cushing basis differential swaps for 5,000 Bbls/D at $1.20/Bbl for July through December 2013.  At June 30, 2013, the fair value of these contracts was a liability of approximately $0.9 million.

 

Counterparty Risk.  At June 30, 2013, Athlon had committed 10% or greater (in terms of fair market value) of its oil derivative contracts in asset positions from the following counterparties, or their affiliates:

 

 

 

Fair Market Value of

 

 

 

Oil Derivative

 

 

 

Contracts

 

Counterparty

 

Committed

 

 

 

(in thousands)

 

BNP Paribas

 

$

3,825

 

Wells Fargo

 

2,318

 

Scotiabank

 

1,474

 

Barclays PLC

 

1,350

 

Royal Bank of Canada

 

1,192

 

 

Athlon does not require collateral from its counterparties for entering into financial instruments, so in order to mitigate the credit risk associated with financial instruments, Athlon enters into master netting agreements with its counterparties.  The master netting agreement is a standardized, bilateral contract between a given counterparty and Athlon.  Instead of treating each financial transaction between the counterparty and Athlon separately, the master netting agreement enables the counterparty and Athlon to aggregate all financial trades and treat them as a single agreement.  This arrangement is intended to benefit Athlon in two ways: (i) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (ii) netting of settlement amounts reduces Athlon’s credit exposure to a given counterparty in the event of close-out.  Athlon’s accounting policy is to not offset fair value amounts between different counterparties for derivative instruments in the accompanying Consolidated Balance Sheets.

 

8



Table of Contents

 

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

Tabular Disclosures of Fair Value Measurements

 

The following table summarizes the fair value of Athlon’s derivative instruments not designated as hedging instruments as of the dates indicated:

 

 

 

Oil

 

Commodity

 

Total

 

Balance Sheet

 

Commodity

 

Derivatives

 

Commodity

 

Location

 

Derivatives

 

Netting (a)

 

Derivatives

 

 

 

 

 

 

 

 

 

As of June 30, 2013

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

Derivatives - current

 

$

5,335

 

$

(2,313

)

$

3,022

 

Derivatives - noncurrent

 

7,392

 

 

7,392

 

Total assets

 

12,727

 

(2,313

)

10,414

 

Liabilities

 

 

 

 

 

 

 

Derivatives - current

 

(2,612

)

2,313

 

(299

)

Derivatives - noncurrent

 

 

 

 

Total liabilities

 

(2,612

)

2,313

 

(299

)

Net assets

 

$

10,115

 

$

 

$

10,115

 

 

 

 

 

 

 

 

 

As of December 31, 2012

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

Derivatives - current

 

$

3,386

 

$

(1,140

)

$

2,246

 

Derivatives - noncurrent

 

3,265

 

(411

)

2,854

 

Total assets

 

6,651

 

(1,551

)

5,100

 

Liabilities

 

 

 

 

 

 

 

Derivatives - current

 

(1,732

)

1,140

 

(592

)

Derivatives - noncurrent

 

(930

)

411

 

(519

)

Total liabilities

 

(2,662

)

1,551

 

(1,111

)

Net assets

 

$

3,989

 

$

 

$

3,989

 

 


(a)         Represents counterparty netting under master netting agreements, which allow for netting of commodity derivative contracts.  These derivative instruments are reflected net on the accompanying Consolidated Balance Sheets.

 

The following table summarizes the effect of derivative instruments not designated as hedges on the accompanying Consolidated Statements of Operations for the periods indicated (in thousands):

 

 

 

 

 

Amount of Gain Recognized in Income

 

 

 

Location of Gain

 

Three months ended June 30,

 

Six months ended June 30,

 

Derivatives Not Designated as Hedges

 

Recognized in Income

 

2013

 

2012

 

2013

 

2012

 

Commodity derivative contracts

 

Derivative fair value gain

 

$

12,555

 

$

46,569

 

$

5,706

 

$

23,858

 

 

Fair Value Hierarchy

 

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).  The three levels of the fair value hierarchy are defined as follows:

 

·      Level 1 — Inputs such as unadjusted, quoted prices that are available in active markets for identical assets or liabilities.

·      Level 2 — Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

·      Level 3 — Inputs that are unobservable for use when little or no market data exists requiring the use of valuation methodologies that result in management’s best estimate of fair value.

 

9



Table of Contents

 

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

As required by GAAP, Athlon utilizes the most observable inputs available for the valuation technique used.  The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement.  Athlon’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels.  The following methods and assumptions were used to estimate the fair values of Athlon’s assets and liabilities that are accounted for at fair value on a recurring basis:

 

·      Level 2 — Fair values of swaps are estimated using a combined income-based and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services.  Athlon’s collars and puts are average value options.  Settlement is determined by the average underlying price over a predetermined period of time.  Athlon uses observable inputs in an option pricing valuation model to determine fair value such as: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract; and (4) appropriate volatilities.

 

Athlon adjusts the valuations from the valuation model for nonperformance risk.  For commodity derivative contracts which are in an asset position, Athlon adds the counterparty’s credit default swap spread to the risk-free rate.  If a counterparty does not have a credit default swap spread, Athlon uses other companies with similar credit ratings to determine the applicable spread.  For commodity derivative contracts which are in a liability position, Athlon uses the yield on its senior notes less the risk-free rate.  All fair values have been adjusted for nonperformance risk resulting in a decrease in the net commodity derivative asset of approximately $111,000 as of June 30, 2013 and an increase in the net commodity derivative asset of approximately $125,000 as of December 31, 2012.

 

The following table sets forth Athlon’s assets and liabilities that were accounted for at fair value on a recurring basis as of the dates indicated:

 

 

 

 

 

Fair Value Measurements at Reporting Date Using

 

 

 

 

 

Quoted Prices in

 

 

 

 

 

 

 

 

 

Active Markets for

 

Significant Other

 

Significant

 

 

 

 

 

Identical Assets

 

Observable Inputs

 

Unobservable Inputs

 

Description

 

Asset (liability), net

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

 

 

(in thousands)

 

As of June 30, 2013

 

 

 

 

 

 

 

 

 

Oil derivative contracts - swaps

 

$

11,049

 

$

 

$

11,049

 

$

 

Oil derivative contracts - basis differential swaps

 

(924

)

 

(924

)

 

Oil derivative contracts - collars

 

(10

)

 

(10

)

 

Total

 

$

10,115

 

$

 

$

10,115

 

$

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2012

 

 

 

 

 

 

 

 

 

Oil derivative contracts - swaps

 

$

4,069

 

$

 

$

4,069

 

$

 

Oil derivative contracts - collars

 

(80

)

 

(80

)

 

Total

 

$

3,989

 

$

 

$

3,989

 

$

 

 

10



Table of Contents

 

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

Note 5. Asset Retirement Obligations

 

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal.  The following table summarizes the changes in Athlon’s asset retirement obligations for the six months ended June 30, 2013 (in thousands):

 

Balance at January 1

 

$

5,049

 

Acquisition of properties

 

265

 

Wells drilled

 

418

 

Accretion of discount

 

311

 

Revisions of previous estimates

 

2

 

Plugging and abandonment costs incurred

 

(66

)

Balance at June 30

 

$

5,979

 

 

As of June 30, 2013, $5.9 million of Athlon’s asset retirement obligations were long-term and recorded in “Asset retirement obligations, net of current portion” and $102,000 were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.

 

Note 6. Long-Term Debt

 

Senior Notes

 

In April 2013, Holdings issued $500 million aggregate principal amount of 7 3/8% senior notes due 2021 (the “Notes”).  The net proceeds from the Notes were used to repay a portion of the outstanding borrowings under Holdings credit agreement, to repay in full and terminate Holdings former second lien term loan, to make a $75 million distribution to Holdings’ Class A limited partners, and for general partnership purposes.  The indenture governing the Notes contains covenants, including, among other things, covenants that restrict Holdings’ ability to:

 

·                  make distributions, investments, or other restricted payments if Holdings’ fixed charge coverage ratio is less than 2.0 to 1.0;

·                  incur additional indebtedness if Holdings’ fixed charge coverage ratio would be less than 2.0 to 1.0; and

·                  create liens, sell assets, consolidate or merge with any other person, or engage in transactions with affiliates.

 

These covenants are subject to a number of important qualifications, limitations, and exceptions.  In addition, the indenture contains other customary terms, including certain events of default upon the occurrence of which the senior notes may be declared immediately due and payable.

 

Under the indenture, starting on April 15, 2016, Holdings will be able to redeem some or all of the Notes at a premium that will decrease over time, plus accrued and unpaid interest to the date of redemption.  Prior to April 15, 2016, Holdings will be able, at its option, to redeem up to 35% of the aggregate principal amount of the Notes at a price of 107.375% of the principal thereof, plus accrued and unpaid interest to the date of redemption, with an amount equal to the net proceeds from certain equity offerings.  In addition, at Holdings’ option, prior to April 15, 2016, Holdings may redeem some or all of the Notes at a redemption price equal to 100% of the principal amount of the Notes, plus an “applicable premium”, plus accrued and unpaid interest to the date of redemption.  If a change of control occurs on or prior to July 15, 2014, Holdings may redeem all, but not less than all, of the notes at 110% of the principal amount thereof plus accrued and unpaid interest to, but not including, the redemption date.  Certain asset dispositions will be triggering events that may require Holdings to repurchase all or any part of a noteholder’s Notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to but excluding the date of repurchase.  Interest on the Notes is payable in cash semi-annually in arrears, commencing on October 15, 2013, through maturity.

 

As a result of the issuance of the Notes, Athlon’s former second lien term loan was paid off and retired and the borrowing base of the credit agreement was reduced resulting in a write off of unamortized debt issuance costs of approximately $2.8 million, which is included in “Interest expense” in the accompanying Consolidated Statements of Operations and “Other” in the operating activities section of the accompanying Consolidated Statements of Cash Flows.

 

Credit Agreement

 

Holdings is a party to an amended and restated credit agreement dated March 19, 2013 (the “Holdings Credit Agreement”), which matures on March 19, 2018.  The Holdings Credit Agreement provides for revolving credit loans to be made to Holdings from time to

 

11



Table of Contents

 

ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

time and letters of credit to be issued from time to time for the account of Holdings or any of its restricted subsidiaries.  The aggregate amount of the commitments of the lenders under the Holdings Credit Agreement is $1.0 billion.  Availability under the Holdings Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations.

 

As of June 30, 2013, the borrowing base was $320 million and there were $43.5 million of outstanding borrowings, $276.5 million of borrowing capacity, and no outstanding letters of credit under the Holdings Credit Agreement.  In conjunction with the offering of the Notes in April 2013 as discussed above, the borrowing base under the Holdings Credit Agreement was reduced to $267.5 million.  In May 2013, Holdings amended the Holdings Credit Agreement to, among other things, increase the borrowing base to $320 million.

 

Obligations under the Holdings Credit Agreement are secured by a first-priority security interest in substantially all of Holdings’ proved reserves and in the equity interests of its operating subsidiaries.  In addition, obligations under the Holdings Credit Agreement are guaranteed by Athlon and Holdings’ operating subsidiaries.

 

Loans under the Holdings Credit Agreement are subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan.  Eurodollar loans under the Holdings Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the Holdings Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table.  Holdings also incurs a quarterly commitment fee on the unused portion of the Holdings Credit Agreement indicated in the following table:

 

Ratio of Outstanding Borrowings to Borrowing Base

 

Unused
Commitment Fee

 

Applicable
Margin for
Eurodollar Loans

 

Applicable
Margin for Base
Rate Loans

 

Less than or equal to .30 to 1

 

0.375

%

1.50

%

0.50

%

Greater than .30 to 1 but less than or equal to .60 to 1

 

0.375

%

1.75

%

0.75

%

Greater than .60 to 1 but less than or equal to .80 to 1

 

0.50

%

2.00

%

1.00

%

Greater than .80 to 1 but less than or equal to .90 to 1

 

0.50

%

2.25

%

1.25

%

Greater than .90 to 1

 

0.50

%

2.50

%

1.50

%

 

The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by Holdings) is the rate equal to the British Bankers Association London Interbank Offered Rate (“LIBOR”) for deposits in dollars for a similar interest period.  The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5%; or (3) except during a “LIBOR Unavailability Period”, the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0%.

 

Any outstanding letters of credit reduce the availability under the Holdings Credit Agreement.  Borrowings under the Holdings Credit Agreement may be repaid from time to time without penalty.

 

The Holdings Credit Agreement contains covenants including, among others, the following:

 

·                  a prohibition against incurring debt, subject to permitted exceptions;

·                  a restriction on creating liens on Holdings’ assets and the assets of its operating subsidiaries, subject to permitted exceptions;

·                  restrictions on merging and selling assets outside the ordinary course of business;

·                  restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

·                  a requirement that Holdings maintain a ratio of consolidated total debt to EBITDAX (as defined in the Holdings Credit Agreement) of not more than 4.75 to 1.0 beginning with the quarter ended June 30, 2013 (which ratio changes to 4.5 to 1.0 beginning with the quarter ended June 30, 2014); and

·                  a provision limiting commodity derivative contracts to a volume not exceeding 85% of projected production from proved reserves for a period not exceeding 66 months from the date the commodity derivative contract is entered into.

 

The Holdings Credit Agreement contains customary events of default, including our failure to comply with the financial ratios described above, which would permit the lenders to accelerate the debt if not cured within applicable grace periods.  If an event of

 

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the Holdings Credit Agreement to be immediately due and payable.

 

Note 7. Stockholders’ Equity

 

In connection with Athlon’s incorporation on April 1, 2013 under the laws of the State of Delaware, it issued 1,000 shares of its common stock to Athlon Holdings GP LLC for an aggregate purchase price of $10.00.  On April 26, 2013, in connection with Athlon’s reorganization transactions, certain holders of limited partner interests in Holdings exchanged their Class A interests and Class B interests for an aggregate of 960,907 shares of Athlon’s common stock.  In connection with the effectiveness of Athlon’s IPO, these shares were subject to an adjustment based on Athlon’s IPO price of $20.00 per share and a 65.266-for-1 stock split resulting in 66,339,615 shares of Athlon’s common stock to be outstanding prior to the closing of the IPO.

 

Note 8. Earnings Per Share

 

Prior to the consummation of Athlon’s IPO, Athlon had 960,907 shares of outstanding common stock.  In conjunction with the closing of the IPO, certain Class A limited partners and Class B limited partners of Holdings that exchanged their interests for shares of Athlon’s common stock were subject to an adjustment based on Athlon’s IPO price of $20.00 per share and an actual 65.266-for-1 stock split.  Following this adjustment and stock split, the number of outstanding shares of Athlon’s common stock increased from 960,907 shares to 66,339,615 shares.  The one-to-one conversion of the Holdings interests in April 2013 to 960,907 shares of Athlon common stock that occurred in connection with the IPO is akin to a stock split and has been treated as such in Athlon’s earnings per share (“EPS”) calculations.  Accordingly, Athlon assumes that 66,339,615 shares of common stock were outstanding during periods prior to Athlon’s IPO for purposes of calculating EPS.

 

The following table reflects the allocation of net income to common stockholders and EPS computations for the periods indicated:

 

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(in thousands, except per share amounts)

 

Basic EPS

 

 

 

 

 

 

 

 

 

Numerator:

 

 

 

 

 

 

 

 

 

Basic net income attributable to stockholders

 

$

23,697

 

$

54,604

 

$

34,576

 

$

44,604

 

Denominator:

 

 

 

 

 

 

 

 

 

Basic weighted average shares outstanding

 

66,340

 

66,340

 

66,340

 

66,340

 

Basic EPS attributable to stockholders

 

$

0.36

 

$

0.82

 

$

0.52

 

$

0.67

 

 

 

 

 

 

 

 

 

 

 

Diluted EPS

 

 

 

 

 

 

 

 

 

Numerator:

 

 

 

 

 

 

 

 

 

Basic net income attributable to stockholders

 

$

23,697

 

$

54,604

 

$

34,576

 

$

44,604

 

Effect of conversion of New Holdings Units to shares of Athlon’s common stock

 

831

 

 

831

 

 

Diluted net income attributable to stockholders

 

$

24,528

 

$

54,604

 

$

35,407

 

$

44,604

 

Denominator:

 

 

 

 

 

 

 

 

 

Basic weighted average shares outstanding

 

66,340

 

66,340

 

66,340

 

66,340

 

Effect of conversion of New Holdings Units to shares of Athlon’s common stock

 

1,856

 

1,856

 

1,856

 

1,856

 

Diluted weighted average shares outstanding

 

68,196

 

68,196

 

68,196

 

68,196

 

Diluted EPS attributable to stockholders

 

$

0.36

 

$

0.80

 

$

0.52

 

$

0.65

 

 

Note 9.  Incentive Stock Plans

 

Class B Interests

 

Holdings’ limited partnership agreement provides for the issuance of Class B limited partner interests.  The Class B interests entitle the holder to participate in the net profits of Holdings, but are subject to various performance criteria.  Class A limited partners are entitled to a return of their initial investment plus interest compounded at 8% annually (the “Class A Preference Amount”).  Upon the occurrence of a liquidity event and after the Class A Preference Amount has been satisfied, 80% and 20% of the remaining net profits will be distributed to holders of Class A interests and Class B interests, respectively.  The Class B interests vest over four or

 

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

five years or upon certain performance thresholds being met by Holdings.  Class B interests can also vest on the occurrence of certain events such as a change in control or in some cases upon termination of employment with Holdings.  As discussed in “Note 1. Formation of the Company and Description of Business”, in connection with Holdings’ corporate reorganization, the holders of the Class B limited partner interests in Holdings exchanged their interests for common stock of Athlon subject to the same conditions and vesting terms.

 

Management had independent valuations prepared for its grants of Class B limited partner interests.  During the three months ended June 30, 2013 and 2012, Athlon recorded approximately $65,000 and $32,000, respectively, of non-cash equity-based compensation expense.  During the six months ended June 30, 2013 and 2012, Athlon recorded approximately $113,000 and $91,000, respectively, of non-cash equity-based compensation expense.  Non-cash equity-based compensation expense is allocated to lease operating expense and general and administrative expenses in the accompanying Consolidated Statements of Operations based on the allocation of the respective employees’ compensation.  During the three and six months ended June 30, 2013, Athlon capitalized approximately $17,000 and $42,000, respectively, of non-cash stock-based compensation expense.  During each of the three and six months ended June 30, 2012, Athlon capitalized approximately $43,000 of non-cash stock-based compensation expense.  Capitalized non-cash stock-based compensation expense is included as a component of “Proved properties, including wells and related equipment” in the accompanying Consolidated Balance Sheets.

 

The fair value of Class B interests granted was estimated on the grant date using an option pricing model based on the following assumptions for the periods indicated:

 

 

 

Six months ended June 30,

 

 

 

2013

 

2012

 

Expected volatility

 

34.1

%

46.3

%

Expected dividend yield

 

0

%

0

%

Expected term (in years)

 

0.53

 

1.63

 

Risk-free interest rate

 

0.11

%

0.24

%

Weighted-average grant date fair value per interest

 

$

1.09

 

$

1.41

 

 

The expected volatility was calculated based on the average historical volatility of each company in Athlon’s peer group based on historical stock price data.  The expected term of the Class B interests was based on expected payout date from a triggering event.  The risk-free interest rate was based on the U.S. Treasury yield curve in effect at the grant date for a period of time commensurate with the expected term of the Class B interests.

 

The following table summarizes the changes in Athlon’s unvested common stock awards which were formerly Class B interests in Holdings for the six months ended June 30, 2013:

 

 

 

 

 

Weighted -

 

 

 

 

 

Average

 

 

 

Number of

 

Grant Date

 

 

 

Shares

 

Fair Value

 

 

 

 

 

 

 

Outstanding at January 1

 

5,021,200

 

$

0.22

 

Granted

 

652,500

 

1.09

 

Vested

 

(1,034,800

)

0.13

 

Forfeited

 

(41,000

)

1.18

 

Outstanding at June 30

 

4,597,900

 

0.36

 

 

As of June 30, 2013, Athlon had approximately $1.6 million of total unrecognized compensation cost related to unvested common stock awards which were formerly Class B interests in Holdings, which is expected to be recognized over a weighted-average period of approximately 3.3 years.  During the six months ended June 30, 2013 and 2012, there were 1,034,800 and 1,015,500, respectively, Class B interests that vested, the total grant date fair value of which was approximately $136,000 and $111,000, respectively.

 

Upon the consummation of Athlon’s IPO on August 1, 2013, the remaining unvested common stock awards, which were formerly Class B interests in Holdings, vested and Athlon recognized non-cash equity-based compensation expense of approximately $1.6 million.

 

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

Note 10. Commitments and Contingencies

 

Athlon is a party to ongoing legal proceedings in the ordinary course of business.  Management does not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on Athlon’s business, financial position, results of operations, or liquidity.

 

Additionally, Holdings has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, commodity derivative contracts, operating leases, and development commitments.

 

Note 11. Related Party Transactions

 

Transaction Fee Agreement

 

Holdings is a party to a Transaction Fee Agreement, dated August 23, 2010, which requires Holdings to pay a fee to Apollo equal to 2% of the total equity contributed to Holdings, as defined in the agreement, in exchange for consulting and advisory services provided by Apollo.  In October 2012, Apollo assigned its rights and obligations under the Transaction Fee Agreement to an affiliate, Apollo Global Securities, LLC.  Since Holdings’ inception through June 30, 2013, it has incurred transaction fees under the Transaction Fee Agreement of approximately $7.5 million in total.  Upon the consummation of Athlon’s IPO, Holdings terminated the Transaction Fee Agreement.

 

Services Agreement

 

Holdings is a party to a Services Agreement, dated August 23, 2010, which requires Holdings to compensate Apollo for consulting and advisory services equal to the higher of (i) 1% of earnings before interest, income taxes, DD&A, and exploration expense per quarter and (ii) $62,500 per quarter (the “Advisory Fee”); provided, however, that such Advisory Fee for any calendar year shall not exceed $500,000.  The Services Agreement also provides for reimbursement to Apollo for any reasonable out-of-pocket expenses incurred while performing services under the Services Agreement.  During the three months ended June 30, 2013 and 2012, Holdings incurred approximately $95,000 and $280,000, respectively, of Advisory Fees.  During the six months ended June 30, 2013 and 2012, Holdings incurred approximately $500,000 and $493,000, respectively, of Advisory Fees.  All fees incurred under the Services Agreement are included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations.

 

The Services Agreement provides that Apollo will provide advisory services until the earliest of (i) August 23, 2020, (ii) such time as Apollo owns in the aggregate less than 5% of the beneficial economic interest of Holdings, and (iii) such date as is mutually agreed upon by Holdings and Apollo.  Upon the consummation of Athlon’s IPO, Holdings terminated the Services Agreement and, in connection with the termination, Apollo received $2.5 million (plus $132,000 of unreimbursed fees) from Holdings.  Such payment corresponds to the present value as of the date of termination of the aggregate annual fees that would have been payable during the remainder of the term of the Services Agreement (assuming a term ending on August 23, 2020).  Under the Services Agreement, Holdings also agreed to indemnify Apollo and its affiliates and their respective limited partners, general partners, directors, members, officers, managers, employees, agents, advisors, their directors, officers, and representatives for potential losses relating to the services contemplated under the Services Agreement.

 

Participation of Apollo Global Securities, LLC in Senior Notes Offering and IPO

 

Apollo Global Securities, LLC is an affiliate of the Apollo Funds and received a portion of the gross spread as an initial purchaser of the Notes of $0.5 million.  Apollo Global Securities, LLC was also an underwriter in Athlon’s IPO and received a portion of the discounts and commissions paid to the underwriters in the IPO of approximately $0.9 million.

 

Distribution

 

Holdings used a portion of the net proceeds from the Notes to make a distribution to its Class A limited partners, including the Apollo Funds and its management team and employees.  The Apollo Funds received approximately $73 million of the distribution and the remaining Class A limited partners received approximately $2 million, in the aggregate.

 

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ATHLON ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(unaudited)

 

Exchange Agreement

 

Upon the consummation of its IPO, Athlon entered into an exchange agreement with certain members of its management team and employees who hold New Holdings Units after the closing of the IPO.  Under the exchange agreement, each such holder (and certain permitted transferees thereof) may, under certain circumstances after the date of the closing of the IPO (subject to the terms of the exchange agreement), exchange their New Holdings Units for shares of Athlon’s common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends, and reclassifications.  As a holder exchanges its New Holdings Units, Athlon’s interest in Holdings will be correspondingly increased.

 

Tax Receivable Agreement

 

Upon the consummation of Athlon’s IPO, it entered into a tax receivable agreement with certain members of its management team and employees who hold New Holdings Units after the closing of the IPO that provides for the payment from time to time by Athlon to such unitholders of Holdings of 85% of the amount of the benefits, if any, that Athlon is deemed to realize as a result of increases in tax basis and certain other tax benefits related to exchanges of New Holdings Units pursuant to the exchange agreement, including tax benefits attributable to payments under the tax receivable agreement.  These payment obligations are obligations of Athlon and not of Holdings.  For purposes of the tax receivable agreement, the benefit deemed realized by Athlon will be computed by comparing its actual income tax liability (calculated with certain assumptions) to the amount of such taxes that Athlon would have been required to pay had there been no increase to the tax basis of the assets of Holdings as a result of the exchanges and had Athlon not entered into the tax receivable agreement.

 

The step-up in basis will depend on the fair value of the New Holdings Units at conversion.  There is no intent of the holders of New Holdings Units to exchange their units for shares of Athlon’s common stock in the foreseeable future.  In addition, Athlon does not expect to be in a tax paying position before 2019.  Therefore, Athlon cannot presently estimate what the benefit or payments under the tax receivable agreement will be on a factually supportable basis.  If the tax receivable agreement had been terminated immediately after the closing of the IPO, Athlon estimates it would have been required to make an early termination payment of approximately $5.3 million to the holders of the New Holdings Units.

 

Note 12. Subsequent Events

 

As discussed in “Note 1. Formation of the Company and Description of Business”, on August 7, 2013, Athlon completed its IPO of 15,789,474 shares of its common stock at $20.00 per share and received net proceeds of approximately $293.4 million, after deducting underwriting discounts and commissions and estimated offering expenses.  Athlon used the net proceeds from the IPO to purchase New Holdings Units from Holdings.  Holdings used the proceeds it received as a result of Athlon’s purchase of New Holdings Units (i) to reduce outstanding borrowings under the Holdings Credit Agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes.

 

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ATHLON ENERGY INC.

 

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

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes in “Item 1. Financial Statements”.  The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources.  Actual results could differ materially from those discussed in these forward-looking statements.  We do not undertake to update, revise, or correct any of the forward-looking information unless required to do so under law.  Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under “Cautionary Note Regarding Forward-Looking Information “ and “Risk Factors” in our final prospectus dated August 1, 2013 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933 on August 5, 2013.

 

Overview

 

We are an independent exploration and production company focused on the acquisition, development, and exploitation of unconventional oil and liquids-rich natural gas reserves in the Permian Basin.  The Permian Basin spans portions of Texas and New Mexico and consists of three primary sub-basins: the Delaware Basin, the Central Basin Platform, and the Midland Basin.  All of our properties are located in the Midland Basin.  Our drilling activity is currently focused on the low-risk vertical development of stacked pay zones, including the Spraberry, Wolfcamp, Cline, Strawn, Atoka, and Mississippian formations, which we refer to collectively as the Wolfberry play.  We are a returns-focused organization and have targeted the Wolfberry play in the Midland Basin because of its favorable operating environment, consistent reservoir quality across multiple target horizons, long-lived reserve characteristics and high drilling success rates.

 

We were founded in August 2010 by a group of executives from Encore Acquisition Company following its acquisition by Denbury Resources, Inc.  With an average of approximately 20 years of industry experience and 10 years of history working together, our founding management has a proven track record of working as a team to acquire, develop, and exploit oil and natural gas reserves in the Permian Basin as well as other resource plays in North America.

 

Initial Public Offering

 

On August 7, 2013, we completed our initial public offering (“IPO”) of 15,789,474 shares of our common stock at $20.00 per share and received net proceeds of approximately $293.4 million, after deducting underwriting discounts and commissions and estimated offering expenses.  Upon closing of the IPO, the limited partnership agreement of Holdings was amended and restated to, among other things, modify Holdings’ capital structure by replacing its different classes of interests with a single new class of units, the “New Holdings Units”.  The members of Holdings’ management team and certain employees who held Class A limited partner interests now own New Holdings Units and entered into an exchange agreement under which (subject to the terms of the exchange agreement) they have the right to exchange their New Holdings Units for shares of our common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends, and reclassifications.  All other New Holdings Units are held by us.  We used the net proceeds from the IPO to purchase New Holdings Units from Holdings.  Holdings used the proceeds it received as a result of our purchase of New Holdings Units (i) to reduce outstanding borrowings under its credit agreement, (ii) to provide additional liquidity for use in its drilling program, and (iii) for general corporate purposes.

 

Factors That Significantly Affect Our Financial Condition and Results of Operations

 

Our revenues, cash flow from operations, and future growth depend substantially on factors beyond our control, such as economic, political, and regulatory developments and competition from other sources of energy.  Oil and natural gas prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters.  Sustained periods of low prices for oil, natural gas, or NGLs could materially and adversely affect our financial condition, our results of operations, the quantities of oil and natural gas that we can economically produce, and our ability to access capital.

 

We use commodity derivative instruments, such as swaps, puts, and collars to manage and reduce price volatility and other market risks associated with our oil production.  These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases.  Our risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions.  We elected not to designate our current portfolio of commodity derivative contracts as hedges for accounting purposes.  Therefore,

 

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Table of Contents

 

changes in fair value of these derivative instruments are recognized in earnings.  Please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion of our commodity derivative contracts.

 

The prices we realize on the oil we produce are affected by the ability to transport crude oil to the Cushing, Oklahoma transport hub and the Gulf Coast refineries.  Periodically, logistical and infrastructure constraints at the Cushing, Oklahoma transport hub have resulted in an oversupply of crude oil at Midland, Texas and thus lower prices for Midland WTI.  These lower prices have adversely affected the prices we realize on oil sales and increased our differential to NYMEX WTI.  However, several projects have recently been implemented and several more are underway to ease these transportation difficulties which we believe could reduce our differentials to NYMEX in the future.  We have also entered into Midland-Cushing differential swaps for 2013 to mitigate the adverse effects of any further widening of the Midland-Cushing WTI differential (the difference between Midland WTI and Cushing WTI).

 

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines.  As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases.  Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces.  We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce.  Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost effective manner.  Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain drilling permits and regulatory approvals.

 

As with our historical acquisitions, any future acquisitions could have a substantial impact on our financial condition and results of operations. In addition, funding future acquisitions may require us to incur additional indebtedness or issue additional equity.

 

The volumes of oil and natural gas that we produce are driven by several factors, including:

 

·                  success in drilling wells, including exploratory wells, and the recompletion of existing wells;

·                  the amount of capital we invest in the leasing and development of our oil and natural gas properties;

·                  facility or equipment availability and unexpected downtime;

·                  delays imposed by or resulting from compliance with regulatory requirements; and

·                  the rate at which production volumes on our wells naturally decline.

 

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

 

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

 

Corporate Reorganization.  We were formed on April 1, 2013.  On April 26, 2013, Athlon Holdings LP (“Holdings”) underwent a corporate reorganization and as a result, Holdings became a majority-owned subsidiary of ours.  We operate and control all of Holdings’ business and affairs and consolidate its financial results.  The historical consolidated financial statements included herein for periods prior to the reorganization transactions are based on Holdings consolidated financial statements.  As a result, the historical financial data may not give you an accurate indication of what our actual results would have been if the reorganization transactions had been completed at the beginning of the periods presented or what our future results of operations are likely to be.

 

Public Company Expenses.  Upon completion of our IPO, we will incur direct, incremental general and administrative (“G&A”) expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and independent director compensation.  We estimate these direct, incremental G&A expenses initially to total approximately $2.0 million per year.  These direct, incremental G&A expenses are not included in our historical results of operations.

 

Income Taxes.  Holdings, our accounting predecessor, is a limited partnership not subject to federal income taxes.  Accordingly, no provision for federal income taxes has been provided for in our historical results of operations for periods prior to the reorganization transactions because taxable income was passed through to Holdings partners.  However, we are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings.

 

Increased Drilling Activity.  We began operations in January 2011 and gradually added operated vertical drilling rigs.  At June 30, 2013, we operated seven vertical drilling rigs on our properties, and we have operated between five and eight drilling rigs since

 

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October 2011.  Our 2013 drilling capital expenditures are expected to be between $340 million and $350 million, plus an additional $15 million for infrastructure, leasing, and capitalized workovers.  We expect to drill 161 gross vertical Wolfberry wells and 4 gross horizontal Wolfcamp wells.  We expect to take delivery of our first horizontal rig in the third quarter of 2013 and our second horizontal rig in the second quarter of 2014.  In 2014, we intend to expand to an eight-rig vertical drilling program.  The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results in each particular year.

 

Senior Notes.  In April 2013, Holdings issued $500 million in aggregate principal amount of 7 3/8% senior notes due 2021 (the “Notes”).  We used the proceeds from the Notes offering to repay a portion of the amounts outstanding under our credit agreement, to repay in full and terminate our second lien term loan, to make a $75 million distribution to our Class A limited partners, and for general partnership purposes.  The Notes bear interest at a rate significantly higher than the rates under our credit agreement which resulted in higher interest expense in the second quarter of 2013 as compared to our historical interest expense.  In the future, we may incur additional indebtedness to fund our acquisition and development activities.  Please read “—Capital Commitments, Capital Resources, and Liquidity—Liquidity” for additional discussion of our financing arrangements.

 

Sources of Our Revenues

 

Our revenues are derived from the sale of oil, natural gas, and NGLs within the continental United States and do not include the effects of derivatives.  For the second quarter of 2013, oil and NGLs represented approximately 81% of our total production volumes.  Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

 

NYMEX WTI and Henry Hub prompt month contract prices are widely-used benchmarks in the pricing of oil and natural gas.  The following table provides the high and low prices for NYMEX WTI and Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated:

 

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Oil

 

 

 

 

 

 

 

 

 

NYMEX WTI High

 

$

98.44

 

$

106.16

 

$

98.44

 

$

109.77

 

NYMEX WTI Low

 

86.68

 

77.69

 

86.68

 

77.69

 

Differential to Average NYMEX WTI

 

(2.43

)

(7.66

)

(6.09

)

(9.53

)

Natural Gas

 

 

 

 

 

 

 

 

 

NYMEX Henry Hub High

 

4.41

 

2.82

 

4.41

 

3.10

 

NYMEX Henry Hub Low

 

3.57

 

1.91

 

3.11

 

1.91

 

Differential to Average NYMEX Henry Hub

 

(0.37

)

(0.19

)

(0.21

)

(0.18

)

 

We normally sell production to a relatively small number of customers.  In 2012, three purchasers individually accounted for more than 10% of our revenues: Pecos Gathering & Marketing (43%); Occidental Petroleum Corporation (29%); and DCP Midstream (12%). If any significant customer decided to stop purchasing oil and natural gas from us, our revenues could decline and our operating results and financial condition could be harmed.  However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our significant customers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

 

Principal Components of Our Cost Structure

 

Lease Operating Expense.  LOE includes the daily costs incurred to bring crude oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties.  Such costs include field personnel compensation, utilities, maintenance, and workover expenses related to our oil and natural gas properties.

 

Production, Severance, and Ad Valorem Taxes.  Production and severance taxes are paid on produced oil, natural gas, and NGLs based on a percentage of revenues from production sold at fixed rates established by federal, state, or local taxing authorities.  In general, the production and severance taxes we pay correlate to the changes in oil and natural gas revenues.  We are also subject to ad valorem taxes primarily in the counties where our production is located.  Ad valorem taxes are generally based on the valuation of our oil and natural gas properties and are assessed annually.

 

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Table of Contents

 

Depreciation, Depletion, and Amortization.  Depreciation, depletion, and amortization (“DD&A”) is the expensing of the capitalized costs incurred to acquire, explore, and develop oil and natural gas.  We use the full cost method of accounting for oil and natural gas activities.

 

General and Administrative Expense.  G&A expense consists of company overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees, and legal compliance costs.  Upon completion of our IPO, G&A expense will also include public company expenses as described above under “—Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations—Public Company Expenses”.

 

Interest Expense.  We finance a portion of our working capital requirements, capital expenditures, and acquisitions with borrowings under our credit agreement.  As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.  Interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, and annual agency fees are included in interest expense.  Interest expense is net of capitalized interest on expenditures made in connection with exploration and development projects that are not subject to current amortization.

 

Derivative Fair Value Gain.  We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil.  We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change.  The commodity derivative contracts we have in place are not designated as hedges for accounting purposes.  Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations.  Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

 

How We Evaluate Our Operations

 

In evaluating our financial results, we focus on the mix of our revenues from oil, natural gas, and NGLs, the average realized price from sales of our production, our production margins, and our net income.  Below are highlights of our financial and operating results for the second quarter of 2013:

 

·                  Our oil, natural gas, and NGLs revenues increased 82% to $65.2 million in the second quarter of 2013 as compared to $35.8 million in the second quarter of 2012.

·                  Our average daily production volumes increased 68% to 11,183 BOE/D in the second quarter of 2013 as compared to 6,641 BOE/D in the second quarter of 2012.  Oil and NGLs represented approximately 81% of our total production volumes in the second quarter of 2013.

·                  Our average realized oil price increased 7% to $91.80 per Bbl in the second quarter of 2013 as compared to $85.84 per Bbl in the second quarter of 2012.  Our average realized natural gas price increased 83% to $3.72 per Mcf in the second quarter of 2013 as compared to $2.03 per Mcf in the second quarter of 2012.  Our average realized NGL price decreased 20% to $27.27 per Bbl in the second quarter of 2013 as compared to $34.29 per Bbl in the second quarter of 2012.

·                  Our production margin increased 94% to $53.1 million in the second quarter of 2013 as compared to $27.4 million in the second quarter of 2012.  Total wellhead revenues per BOE increased 8% and total production expenses per BOE decreased 15%.  On a per BOE basis, our production margin increased 15% to $52.16 per BOE in the second quarter of 2013 as compared to $45.31 per BOE for the second quarter of 2012.

·                  We invested $106.4 million in oil and natural gas activities, of which $98.7 million was invested in development and exploration activities, yielding 44 gross (42 net) productive wells, and $7.7 million was invested in acquisitions of oil and natural gas properties.

 

We also evaluate our rates of return on invested capital in our wells.  We believe the quality of our assets combined with the technical capabilities of our management team can generate attractive rates of return as we develop our extensive resource base.  Additionally, by focusing on concentrated acreage positions, we can build and own centralized production infrastructure, including saltwater disposal facilities, which enable us to reduce reliance on outside service companies, minimize costs, and increase our returns.

 

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Table of Contents

 

Results of Operations

 

Comparison of Quarter Ended June 30, 2013 to Quarter Ended June 30, 2012

 

Revenues.  The following table provides the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

 

 

 

Three months ended June 30,

 

Increase / (Decrease)

 

 

 

2013

 

2012

 

$

 

%

 

Revenues (in thousands):

 

 

 

 

 

 

 

 

 

Oil

 

$

54,609

 

$

29,617

 

$

24,992

 

84

%

Natural gas

 

4,363

 

1,492

 

2,871

 

192

%

NGLs

 

6,193

 

4,682

 

1,511

 

32

%

Total revenues

 

$

65,165

 

$

35,791

 

$

29,374

 

82

%

 

 

 

 

 

 

 

 

 

 

Average realized prices:

 

 

 

 

 

 

 

 

 

Oil ($/Bbl) (excluding impact of cash settled derivatives)

 

$

91.80

 

$

85.84

 

$

5.96

 

7

%

Oil ($/Bbl) (after impact of cash settled derivatives)

 

$

91.03

 

$

85.61

 

$

5.42

 

6

%

Natural gas ($/Mcf)

 

$

3.72

 

$

2.03

 

$

1.69

 

83

%

NGLs ($/Bbl)

 

$

27.27

 

$

34.29

 

$

(7.02

)

-20

%

Combined ($/BOE) (excluding impact of cash settled derivatives)

 

$

64.04

 

$

59.22

 

$

4.82

 

8

%

Combined ($/BOE) (after impact of cash settled derivatives)

 

$

63.59

 

$

59.09

 

$

4.50

 

8

%

 

 

 

 

 

 

 

 

 

 

Total production volumes:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

595

 

345

 

250

 

72

%

Natural gas (MMcf)

 

1,174

 

736

 

438

 

60

%

NGLs (MBbls)

 

227

 

137

 

90

 

66

%

Combined (MBOE)

 

1,018

 

604

 

414

 

69

%

 

 

 

 

 

 

 

 

 

 

Average daily production volumes:

 

 

 

 

 

 

 

 

 

Oil (Bbls/D)

 

6,537

 

3,792

 

2,745

 

72

%

Natural gas (Mcf/D)

 

12,897

 

8,093

 

4,804

 

59

%

NGLs (Bbls/D)

 

2,496

 

1,501

 

995

 

66

%

Combined (BOE/D)

 

11,183

 

6,641

 

4,542

 

68

%

 

The following table shows the relationship between our average oil and natural gas realized prices as a percentage of average NYMEX prices for the periods indicated.  Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

 

 

 

Three months ended June 30,

 

 

 

2013

 

2012

 

Average realized oil price ($/Bbl)

 

$

91.80

 

$

85.84

 

Average NYMEX ($/Bbl)

 

$

94.23

 

$

93.50

 

Differential to NYMEX

 

$

(2.43

)

$

(7.66

)

Average realized oil price to NYMEX percentage

 

97

%

92

%

 

 

 

 

 

 

Average realized natural gas price ($/Mcf)

 

$

3.72

 

$

2.03

 

Average NYMEX ($/Mcf)

 

$

4.09

 

$

2.22

 

Differential to NYMEX

 

$

(0.37

)

$

(0.19

)

Average realized natural gas price to NYMEX percentage

 

91

%

91

%

 

Our average realized oil price as a percentage of the average NYMEX price improved to 97% for the second quarter of 2013 as compared to 92% for the second quarter of 2012.  All of our oil contracts are impacted by the Midland-Cushing differential, which narrowed to a negative $0.15 per Bbl in the second quarter of 2013 as compared to a negative $4.90 per Bbl in the second quarter of 2012 primarily due to the implementation of several infrastructure projects which have eased difficulties experienced during 2012 transporting oil from the Permian Basin to Gulf Coast refineries.  Our average realized natural gas price as a percentage of the average NYMEX price remained constant at 91%.

 

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Table of Contents

 

Oil revenues increased 84% from $29.6 million in the second quarter of 2012 to $54.6 million in the second quarter of 2013 as a result of an increase in our oil production volumes of 250 MBbls and a $5.96 per Bbl increase in our average realized oil price.  Our higher oil production increased oil revenues by $21.4 million and was primarily the result of our development program in the Permian Basin.  Our higher average realized oil price increased oil revenues by $3.5 million and was primarily due to a higher average NYMEX price, which increased from $93.50 per Bbl in the second quarter of 2012 to $94.23 per Bbl in the second quarter of 2013, and the tightening of our oil differentials as previously discussed.

 

Natural gas revenues increased 192% from $1.5 million in the second quarter of 2012 to $4.4 million in the second quarter of 2013 as a result of an increase in our natural gas production volumes of 438 MMcf and a $1.69 per Mcf increase in our average realized natural gas price.  Our higher average realized natural gas price increased natural gas revenues by $2.0 million and was primarily due to a higher average NYMEX price, which increased from $2.22 per Mcf in the second quarter of 2012 to $4.09 per Mcf in the second quarter of 2013.  Our higher natural gas production increased natural gas revenues by $0.9 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring a portion of our natural gas production as either (1) our well is not yet tied into the third-party gathering system, (2) the pressures on the third-party gathering system are too high to allow additional production from our well to be transported, or (3) our production is prorated due to high demand on the third-party gathering system.  During the second quarter of 2013, we estimate that we flared approximately 3.9 MMcfe/D net, which included both residue gas and NGL production.  We expect to continue flaring until further improvements can be made to various third-party gathering systems, which are scheduled to occur late in the third quarter of 2013.

 

NGL revenues increased 32% from $4.7 million in the second quarter of 2012 to $6.2 million in the second quarter of 2013 as a result of an increase in our NGL production volumes of 90 MBbls, partially offset by a $7.02 per Bbl decrease in our average realized NGL price.  Our higher NGL production increased NGL revenues by $3.1 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring as described above.  Our lower average realized NGL price decreased NGL revenues by $1.6 million and was primarily due to increased supplies of NGLs from NGL-rich shales in the Permian Basin and other basins including the Eagle Ford and the Williston.

 

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Table of Contents

 

Expenses.  The following table summarizes our expenses for the periods indicated:

 

 

 

Three months ended June 30,

 

Increase / (Decrease)

 

 

 

2013

 

2012

 

$

 

%

 

Expenses (in thousands):

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

Lease operating

 

$

7,775

 

$

5,942

 

$

1,833

 

31

%

Production, severance, and ad valorem taxes

 

4,247

 

2,461

 

1,786

 

73

%

Processing, gathering, and overhead

 

65

 

2

 

63

 

3150

%

Total production expenses

 

12,087

 

8,405

 

3,682

 

44

%

Other:

 

 

 

 

 

 

 

 

 

Depletion, depreciation, and amortization

 

20,358

 

13,065

 

7,293

 

56

%

General and administrative

 

3,659

 

2,481

 

1,178

 

47

%

Derivative fair value gain

 

(12,555

)

(46,569

)

34,014

 

-73

%

Accretion

 

162

 

114

 

48

 

42

%

Total operating

 

23,711

 

(22,504

)

46,215

 

-205

%

Interest

 

12,082

 

1,705

 

10,377

 

609

%

Income tax provision

 

4,844

 

1,986

 

2,858

 

144

%

Total expenses

 

$

40,637

 

$

(18,813

)

$

59,450

 

-316

%

 

 

 

 

 

 

 

 

 

 

Expenses (per BOE):

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

Lease operating

 

$

7.64

 

$

9.83

 

$

(2.19

)

-22

%

Production, severance, and ad valorem taxes

 

4.18

 

4.07

 

0.11

 

3

%

Processing, gathering, and overhead

 

0.06

 

 

0.06

 

0

%

Total production expenses

 

11.88

 

13.90

 

(2.02

)

-15

%

Other:

 

 

 

 

 

 

 

 

 

Depletion, depreciation, and amortization

 

20.01

 

21.62

 

(1.61

)

-7

%

General and administrative

 

3.60

 

4.11

 

(0.51

)

-12

%

Derivative fair value gain

 

(12.34

)

(77.06

)

64.72

 

-84

%

Accretion

 

0.16

 

0.19

 

(0.03

)

-16

%

Total operating

 

23.31

 

(37.24

)

60.55

 

-163

%

Interest

 

11.87

 

2.82

 

9.05

 

321

%

Income tax provision

 

4.76

 

3.29

 

1.47

 

45

%

Total expenses

 

$

39.94

 

$

(31.13

)

$

71.07

 

-228

%

 

Production expenses.  Production expenses attributable to LOE increased 31% from $5.9 million in the second quarter of 2012 to $7.8 million in the second quarter of 2013 as a result of an increase in production volumes from wells drilled, which contributed $4.1 million of additional LOE, partially offset by a $2.19 decrease in the average per BOE rate, which would have reduced LOE by $2.2 million if production had been unchanged.  The decrease in our average LOE per BOE rate was attributable to wells we successfully drilled and completed in 2012 and the first half of 2013 where we are experiencing economies of scale from our drilling program and from savings achieved through 2012 infrastructure projects that have resulted in material efficiencies in our field operations and, in particular, our disposal of saltwater.

 

Production expenses attributable to production, severance, and ad valorem taxes increased 73% from $2.5 million in the second quarter of 2012 to $4.2 million in the second quarter of 2013 primarily due to higher wellhead revenues resulting from increased production from our drilling activity.  As a percentage of wellhead revenues, production, severance, and ad valorem taxes decreased to 6.5% in the second quarter of 2013 as compared to 6.9% in the second quarter of 2012 primarily due to an increase in the number of wells brought on production in the second quarter of 2013 as compared to the second quarter of 2012 as we had an additional rig and continue to utilize more efficient drilling rigs and reduce our time from spud to rig release.

 

DD&A expense.  DD&A expense increased 56% from $13.1 million in the second quarter of 2012 to $20.4 million in the second quarter of 2013 primarily due to an increase in production volumes and an increase in our asset base subject to amortization as a result of our drilling activity in 2012 and the first half of 2013.

 

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Table of Contents

 

G&A expense.  G&A expense increased 47% from $2.5 million in the second quarter of 2012 to $3.7 million in the second quarter of 2013 primarily due to (i) higher payroll and payroll-related costs as we continue to add employees in order to manage our growing asset base and (ii) nonrecurring corporate reorganization costs related to the transition from a partnership to a corporation of $0.5 million.

 

Derivative fair value gain.  During the second quarter of 2013, we recorded a $12.6 million derivative fair value gain as compared to $46.6 million in the second quarter of 2012.  Since we do not use hedge accounting, changes in fair value of our derivatives are recognized as gains and losses in the current period.  Included in these amounts were total cash settlements paid on derivatives adjusted for recovered premiums during the second quarter of 2013 were $457,000 as compared to $78,000 during the second quarter of 2012.

 

Interest expense.  Interest expense increased from $1.7 million in the second quarter of 2012 to $12.1 million in the second quarter of 2013 due to higher long-term debt balances and higher borrowing costs in the second quarter of 2013 when compared to the second quarter of 2012.  Our weighted-average total debt was $517.0 million for the second quarter of 2013 as compared to $207.4 million for the second quarter of 2012.  This increase in total debt was due to (1) funding requirements to develop our oil and natural gas properties that are not covered by our operating cash flows and (2) a $75 million distribution to Holdings Class A limited partners in April 2013.  Also, as a result of the issuance of the Notes, our former second lien term loan was paid off and retired and the borrowing base of our credit agreement was reduced resulting in a write off of unamortized debt issuance costs of approximately $2.8 million to interest expense.

 

Our weighted-average interest rate increased to 9.3% for the second quarter of 2013 as compared to 3.3% for the second quarter of 2012.  This increase in borrowing cost is primarily due to the issuance of the Notes, a portion of the net proceeds from which were used to substantially pay down outstanding borrowings on our credit agreement that were subject to lower interest rates than borrowings on the Notes.  The 9.3% weighted-average interest expense for the second quarter of 2013 includes the impact of the write off of unamortized debt issuance costs and is expected to decline in future periods as we are not anticipating a need for a similar write off and as borrowings on the credit agreement increase relative to the Notes resulting in a lower average interest rate.

 

The following table provides the components of our interest expense for the periods indicated:

 

 

 

Three months ended June 30,

 

Increase /

 

 

 

2013

 

2012

 

(Decrease)

 

 

 

(in thousands)

 

Credit agreement

 

$

687

 

$

1,562

 

$

(875

)

Senior notes

 

7,708

 

 

7,708

 

Former second lien term loan

 

427

 

 

427

 

Write off of debt issuance costs

 

2,838

 

 

2,838

 

Amortization of debt issuance costs

 

491

 

143

 

348

 

Less: interest capitalized

 

(69

)

 

(69

)

Total

 

$

12,082

 

$

1,705

 

$

10,377

 

 

Income taxes.  In the second quarter of 2013, we recorded an income tax provision of $4.8 million as compared to $2.0 million in the second quarter of 2012.  In the second quarter of 2013, we had income before income taxes and noncontrolling interest of $29.4 million as compared to $56.6 million in the second quarter of 2012.  Our effective tax rate increased to 16.5% in the second quarter of 2013 as compared to 3.5% in the second quarter of 2012 as a result of our corporate reorganization on April 26, 2013 in which Athlon (a C-corporation) obtained most of the interests in Holdings.  Prior to April 26, 2013, Holdings, our accounting predecessor, was a limited partnership not subject to federal income taxes.

 

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Table of Contents

 

Comparison of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2012

 

Revenues.  The following table provides the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

 

 

 

Six months ended June 30,

 

Increase / (Decrease)

 

 

 

2013

 

2012

 

$

 

%

 

Revenues (in thousands):

 

 

 

 

 

 

 

 

 

Oil

 

$

100,268

 

$

57,050

 

$

43,218

 

76

%

Natural gas

 

7,730

 

2,940

 

4,790

 

163

%

NGLs

 

11,913

 

9,033

 

2,880

 

32

%

Total revenues

 

$

119,911

 

$

69,023

 

$

50,888

 

74

%

 

 

 

 

 

 

 

 

 

 

Average realized prices:

 

 

 

 

 

 

 

 

 

Oil ($/Bbl) (excluding impact of cash settled derivatives)

 

$

88.19

 

$

91.82

 

$

(3.63

)

-4

%

Oil ($/Bbl) (after impact of cash settled derivatives)

 

$

87.51

 

$

87.35

 

$

0.16

 

0

%

Natural gas ($/Mcf)

 

$

3.51

 

$

2.31

 

$

1.20

 

52

%

NGLs ($/Bbl)

 

$

29.08

 

$

37.80

 

$

(8.72

)

-23

%

Combined ($/BOE) (excluding impact of cash settled derivatives)

 

$

62.65

 

$

64.38

 

$

(1.73

)

-3

%

Combined ($/BOE) (after impact of cash settled derivatives)

 

$

62.25

 

$

61.79

 

$

0.46

 

1

%

 

 

 

 

 

 

 

 

 

 

Total production volumes:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

1,137

 

621

 

516

 

83

%

Natural gas (MMcf)

 

2,204

 

1,271

 

933

 

73

%

NGLs (MBbls)

 

410

 

239

 

171

 

72

%

Combined (MBOE)

 

1,914

 

1,072

 

842

 

79

%

 

 

 

 

 

 

 

 

 

 

Average daily production volumes:

 

 

 

 

 

 

 

 

 

Oil (Bbls/D)

 

6,281

 

3,414

 

2,867

 

84

%

Natural gas (Mcf/D)

 

12,176

 

6,982

 

5,194

 

74

%

NGLs (Bbls/D)

 

2,263

 

1,313

 

950

 

72

%

Combined (BOE/D)

 

10,574

 

5,891

 

4,683

 

79

%

 

The following table shows the relationship between our average oil and natural gas realized prices as a percentage of average NYMEX prices for the periods indicated.  Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

 

 

 

Six months ended June 30,

 

 

 

2013

 

2012

 

Average realized oil price ($/Bbl)

 

$

88.19

 

$

91.82

 

Average NYMEX ($/Bbl)

 

$

94.28

 

$

101.35

 

Differential to NYMEX

 

$

(6.09

)

$

(9.53

)

Average realized oil price to NYMEX percentage

 

94

%

91

%

 

 

 

 

 

 

Average realized natural gas price ($/Mcf)

 

$

3.51

 

$

2.31

 

Average NYMEX ($/Mcf)

 

$

3.72

 

$

2.49

 

Differential to NYMEX

 

$

(0.21

)

$

(0.18

)

Average realized natural gas price to NYMEX percentage

 

94

%

93

%

 

Our average realized oil price as a percentage of the average NYMEX price improved to 94% for the first six months of 2013 as compared to 91% for the first six months of 2012, primarily due to the alleviation of certain capacity constraints between the Midland Basin, Cushing, Oklahoma, and Gulf Coast refineries.  Our average realized natural gas price as a percentage of the average NYMEX price remained relatively constant at 94% for the first six months of 2013 as compared to 93% for the first six months of 2012.

 

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Table of Contents

 

Oil revenues increased 76% from $57.1 million in the first six months of 2012 to $100.3 million in the first six months of 2013 as a result of an increase in our oil production volumes of 516 MBbls, partially offset by a $3.63 per Bbl decrease in our average realized oil price.  Our higher oil production increased oil revenues by $47.3 million and was primarily the result of our development program in the Permian Basin.  Our lower average realized oil price decreased oil revenues by $4.1 million and was primarily due to a lower average NYMEX price, which decreased from $101.35 per Bbl in the first six months of 2012 to $94.28 per Bbl in the first six months of 2013, partially offset by the narrowing of our oil differentials as previously discussed.

 

Natural gas revenues increased 163% from $2.9 million in the first six months of 2012 to $7.7 million in the first six months of 2013 as a result of an increase in our natural gas production volumes of 933 MMcf and a $1.20 per Mcf increase in our average realized natural gas price.  Our higher average realized natural gas price increased natural gas revenues by $2.6 million and was primarily due to a higher average NYMEX price, which increased from $2.49 per Mcf in the first six months of 2012 to $3.72 per Mcf in the first six months of 2013.  Our higher natural gas production increased natural gas revenues by $2.2 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring a portion of our natural gas production as either (1) our well is not yet tied into the third-party gathering system, (2) the pressures on the third-party gathering system are too high to allow additional production from our well to be transported, or (3) our production is prorated due to high demand on the third-party gathering system.  During the first six months of 2013, we estimate that we flared approximately 2.9 MMcfe/D net, which included both residue gas and NGL production.  We expect to continue flaring until further improvements can be made to various third-party gathering systems, which are scheduled to occur late in the third quarter of 2013.

 

NGL revenues increased 32% from $9.0 million in the first six months of 2012 to $11.9 million in the first six months of 2013 as a result of an increase in our NGL production volumes of 171 MBbls, partially offset by an $8.72 per Bbl decrease in our average realized NGL price.  Our higher NGL production increased NGL revenues by $6.5 million and was primarily the result of our development program in the Permian Basin, partially offset by flaring as described above.  Our lower average realized NGL price decreased NGL revenues by $3.6 million and was primarily due to increased supplies of NGLs from NGL-rich shales in the Permian Basin and other basins including the Eagle Ford and the Williston.

 

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Table of Contents

 

Expenses.  The following table summarizes our expenses for the periods indicated:

 

 

 

Six months ended June 30,

 

Increase / (Decrease)

 

 

 

2013

 

2012

 

$

 

%

 

Expenses (in thousands):

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

Lease operating

 

$

15,012

 

$

10,641

 

$

4,371

 

41

%

Production, severance, and ad valorem taxes

 

7,941

 

4,811

 

3,130

 

65

%

Processing, gathering, and overhead

 

110

 

26

 

84

 

323

%

Total production expenses

 

23,063

 

15,478

 

7,585

 

49

%

Other:

 

 

 

 

 

 

 

 

 

Depletion, depreciation, and amortization

 

38,411

 

22,679

 

15,732

 

69

%

General and administrative

 

6,998

 

5,078

 

1,920

 

38

%

Derivative fair value gain

 

(5,706

)

(23,858

)

18,152

 

-76

%

Accretion

 

311

 

220

 

91

 

41

%

Total operating

 

63,077

 

19,597

 

43,480

 

222

%

Interest

 

16,556

 

3,200

 

13,356

 

417

%

Income tax provision

 

4,871

 

1,622

 

3,249

 

200

%

Total expenses

 

$

84,504

 

$

24,419

 

$

60,085

 

246

%

 

 

 

 

 

 

 

 

 

 

Expenses (per BOE):

 

 

 

 

 

 

 

 

 

Production:

 

 

 

 

 

 

 

 

 

Lease operating

 

$

7.84

 

$

9.93

 

$

(2.09

)

-21

%

Production, severance, and ad valorem taxes

 

4.15

 

4.48

 

(0.33

)

-7

%

Processing, gathering, and overhead

 

0.06

 

0.02

 

0.04

 

200

%

Total production expenses

 

12.05

 

14.43

 

(2.38

)

-16

%

Other:

 

 

 

 

 

 

 

 

 

Depletion, depreciation, and amortization

 

20.07

 

21.15

 

(1.08

)

-5

%

General and administrative

 

3.66

 

4.74

 

(1.08

)

-23

%

Derivative fair value gain

 

(2.98

)

(22.25

)

19.27

 

-87

%

Accretion

 

0.16

 

0.21

 

(0.05

)

-24

%

Total operating

 

32.96

 

18.28

 

14.68

 

80

%

Interest

 

8.65

 

2.98

 

5.67

 

190

%

Income tax provision

 

2.55

 

1.51

 

1.04

 

69

%

Total expenses

 

$

44.16

 

$

22.77

 

$

21.39

 

94

%

 

Production expenses.  Production expenses attributable to LOE increased 41% from $10.6 million in the first six months of 2012 to $15.0 million in the first six months of 2013 as a result of an increase in production volumes from wells drilled, which contributed $8.4 million of additional LOE, partially offset by a $2.09 decrease in the average per BOE rate, which would have reduced LOE by $4.0 million if production had been unchanged. The decrease in our average LOE per BOE rate was attributable to wells we successfully drilled and completed in 2012 and the first half of 2013 where we are experiencing economies of scale from our drilling program and from savings achieved through 2012 infrastructure projects that have resulted in material efficiencies in our field operations and, in particular, our disposal of saltwater.

 

Production expenses attributable to production, severance, and ad valorem taxes increased 65% from $4.8 million in the first six months of 2012 to $7.9 million in the first six months of 2013 primarily due to higher wellhead revenues resulting from increased production from our drilling activity.  As a percentage of wellhead revenues, production, severance, and ad valorem taxes decreased to 6.6% in the first six months of 2013 as compared to 7.0% in the first six months of 2012 primarily due to an increase in the number of wells brought on production in the first six months of 2013 as compared to the first six months of 2012 as we continue to utilize more efficient drilling rigs and reduce our time from spud to rig release.

 

DD&A expense.  DD&A expense increased 69% from $22.7 million in the first six months of 2012 to $38.4 million in the first six months of 2013 primarily due to an increase in production volumes and an increase in our asset base subject to amortization as a result of our drilling activity in 2012 and the first half of 2013.

 

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G&A expense.  G&A expense increased 38% from $5.1 million in the first six months of 2012 to $7.0 million in the first six months of 2013 primarily due to (i) higher payroll and payroll-related costs as we continue to add employees in order to manage our growing asset base and (ii) nonrecurring corporate reorganization costs related to the transition from a partnership to a corporation of $0.5 million.

 

Derivative fair value gain.  During the first six months of 2013, we recorded a $5.7 million derivative fair value gain as compared to a gain of $23.9 million in the first six months of 2012.  Since we do not use hedge accounting, changes in fair value of our derivatives are recognized as gains and losses in the current period.  Included in these amounts were total cash settlements paid on derivatives adjusted for recovered premiums during the first six months of 2013 were $775,000 as compared to $2.8 million during the first six months of 2012.

 

Interest expense.  Interest expense increased from $3.2 million in the first six months of 2012 to $16.6 million in the first six months of 2013 due to higher long-term debt balances and higher borrowing costs in the first six months of 2013 when compared to the first six months of 2012.  Our weighted-average total debt was $457.4 million for the first six months of 2013 as compared to $188.4 million for the first six months of 2012.  This increase in total debt was due to (1) funding requirements to develop our oil and natural gas properties that are not covered by our operating cash flows and (2) a $75 million distribution to Holdings Class A limited partners in April 2013.  Also, as a result of the issuance of the Notes, our former second lien term loan was paid off and retired and the borrowing base of our credit agreement was reduced resulting in a write off of unamortized debt issuance costs of approximately $2.8 million to interest expense.

 

Our weighted-average interest rate increased to 7.2% for the first six months of 2013 as compared to 3.4% for the first six months of 2012.  This increase in borrowing cost is primarily due to the issuance of the Notes, a portion of the net proceeds from which were used to substantially pay down outstanding borrowings on our credit agreement that were subject to lower interest rates than borrowings on the Notes.  The 7.2% weighted-average interest expense for the first six months of 2013 includes the impact of the write off of unamortized debt issuance costs and is expected to decline in future periods as we are not anticipating a need for a similar write off and as borrowings on the credit agreement increase relative to the Notes resulting in a lower average interest rate.

 

The following table provides the components of our interest expense for the periods indicated:

 

 

 

Six months ended June 30,

 

Increase /

 

 

 

2013

 

2012

 

(Decrease)

 

 

 

(in thousands)

 

Credit agreement

 

$

2,610

 

$

2,921

 

$

(311

)

Senior notes

 

7,708

 

 

7,708

 

Former second lien term loan

 

2,777

 

 

2,777

 

Write off of debt issuance costs

 

2,838

 

 

2,838

 

Amortization of debt issuance costs

 

734

 

279

 

455

 

Less: interest capitalized

 

(111

)

 

(111

)

Total

 

$

16,556

 

$

3,200

 

$

13,356

 

 

Income taxes.  In the first six months of 2013, we recorded an income tax provision of $4.9 million as compared to $1.6 million in the first six months 2012.  In the first six months of 2013, we had income before income taxes and noncontrolling interest of $40.3 million as compared to $46.2 million in the first six months of 2012.  Our effective tax rate increased to 12.1% in the first six months of 2013 as compared to 3.5% in the first six months of 2012 as a result of our corporate reorganization on April 26, 2013 in which Athlon (a C-corporation) obtained most of the interests in Holdings.  Prior to April 26, 2013, Holdings, our accounting predecessor, was a limited partnership not subject to federal income taxes.

 

Capital Commitments, Capital Resources, and Liquidity

 

Capital commitments

 

Our primary uses of cash are:

·                  Development and exploration of oil and natural gas properties;

·                  Acquisitions of oil and natural gas properties;

·                  Funding of working capital; and

 

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·                  Contractual obligations.

 

Development and exploration of oil and natural gas properties.  The following table summarizes our costs incurred related to development and exploration activities for the periods indicated:

 

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

(in thousands)

 

Development (a)

 

$

41,215

 

$

36,330

 

$

90,453

 

$

60,700

 

Exploration (b)

 

57,479

 

32,356

 

80,032

 

57,227

 

Total

 

$

98,694

 

$

68,686

 

$

170,485

 

$

117,927

 

 


(a)              Includes asset retirement obligations incurred of $67,000 and $89,000 during the three months ended June 30, 2013 and 2012, respectively, and $226,000 and $163,000 during the six months ended June 30, 2013 and 2012, respectively.

(b)              Includes asset retirement obligations incurred of $100,000 and $89,000 during the three months ended June 30, 2013 and 2012, respectively, and $194,000 and $161,000 during the six months ended June 30, 2013 and 2012, respectively.

 

Our development capital primarily relates to the drilling of development and infill wells, workovers of existing wells, and the construction of field related facilities.  Our development capital for the second quarter of 2013 yielded 14 gross (14 net) productive wells and no dry holes.  Our development capital for the first six months of 2013 yielded 33 gross (33 net) productive wells and no dry holes.

 

Our exploration expenditures primarily relate to the drilling of exploratory wells, seismic costs, delay rentals, and geological and geophysical costs.  Our exploration capital for the second quarter of 2013 yielded 30 gross (28 net) productive wells and no dry holes.  Our exploration capital for the first six months of 2013 yielded 46 gross (43 net) productive wells and no dry holes.

 

Our development and exploration activities in the second quarter and first six months of 2013 were higher than in the comparable periods of 2012 primarily due to our utilization of more efficient vertical drilling rigs that have significantly reduced the time from spud to rig release allowing us to drill more wells.

 

In 2013, we expect our drilling capital expenditures to be between $340 million to $350 million, plus an additional $15 million for leasing, infrastructure, and capital workovers, and drill 161 gross vertical Wolfberry wells and 4 gross horizontal Wolfcamp wells.

 

Acquisitions of oil and natural gas properties.  We did not have any significant acquisitions of oil and natural gas properties in either the first six months of 2013 or the first six months of 2012.

 

Funding of working capital.  As of June 30, 2013 and December 31, 2012, our working capital deficit (defined as total current assets less total current liabilities) was $42.9 million and $22.2 million, respectively.  Since our principal source of operating cash flows comes from proved reserves to be produced in future periods, which cannot be reported as working capital, we often have negative working capital.  For the remainder of 2013, we expect to continue to have working capital deficits primarily due to amounts accrued related to our extensive development activities.  We expect that our cash flows from operating activities and availability under our credit agreement after application of the net proceeds from our IPO will be sufficient to fund our working capital needs, capital expenditures, and other obligations for at least the next 12 months.  We expect that our production volumes, commodity prices, and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

 

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Contractual obligations.  The following table provides our contractual obligations and commitments as of June 30, 2013:

 

 

 

Payments Due by Period

 

Contractual Obligations and
Commitments

 

Total

 

Six Months
Ending
December 31,
2013

 

Years Ending
December 31,
2014 - 2015

 

Years Ending
December 31,
2016 - 2017

 

Thereafter

 

 

 

(in thousands)

 

Credit agreement (1)

 

$

46,971

 

$

368

 

$

1,473

 

$

1,473

 

$

43,657

 

Senior notes (1)

 

787,271

 

18,437

 

73,750

 

73,750

 

621,334

 

Commodity derivative contracts (2)

 

1,133

 

1,133

 

 

 

 

Development commitments (3)

 

49,345

 

49,345

 

 

 

 

Operating leases and commitments (4)

 

1,551

 

235

 

938

 

378

 

 

Asset retirement obligations (5)

 

35,970

 

102

 

 

 

35,868

 

Total

 

$

922,241

 

$

69,620

 

$

76,161

 

$

75,601

 

$

700,859

 

 


(1)         Includes principal and projected interest payments.  Please read “—Liquidity” for additional information regarding our long-term debt.

(2)         Represents net liabilities for our commodity derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk.  As of June 30, 2013, the fair value of our 2014 and 2015 commodity derivative contracts was a net asset of $11.2 million.  Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information regarding our commodity derivative contracts.

(3)         Represents authorized purchases for work in process related to our drilling activities.

(4)         Represents operating leases that have non-cancelable lease terms in excess of one year.

(5)         Represents the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors.

 

Off-balance sheet arrangements.  We have no investments in unconsolidated entities or persons that could materially affect our liquidity or the availability of capital resources.  We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, an effect on our financial condition or results of operations.

 

Capital resources

 

The following table summarizes our cash flows for the periods indicated:

 

 

 

Six months ended June 30,

 

Increase /

 

 

 

2013

 

2012

 

(Decrease)

 

 

 

(in thousands)

 

Net cash provided by operating activities

 

$

79,224

 

$

42,175

 

$

37,049

 

Net cash used in investing activities

 

(178,332

)

(125,299

)

(53,033

)

Net cash provided by financing activities

 

92,784

 

56,110

 

36,674

 

Net decrease in cash

 

$

(6,324

)

$

(27,014

)

$

20,690

 

 

Cash flows from operating activities.  Cash provided by operating activities increased $37.0 million from $42.2 million in the first six months of 2012 to $79.2 million in the first six months of 2013, primarily due to an increase in our production margin due to a 79% increase in our total production volumes as a result of wells drilled, partially offset by increased expenses as a result of having more producing wells in the first six months of 2013 as compared to the first six months of 2012.

 

Cash flows used in investing activities.  Cash used in investing activities increased $53.0 million from $125.3 million in the first six months of 2012 to $178.3 million in the first six months of 2013, primarily due to a $39.5 million increase in amounts paid to develop oil and natural gas properties as we utilized more efficient vertical drilling rigs that have significantly reduced the time from spud to rig release allowing us to drill and complete more wells over the same time period.

 

Cash flows from financing activities.  Our cash flows from financing activities have historically consisted of net proceeds from and payments on long-term debt and contributions from partners.  We periodically draw on our credit agreement and seek funding from partners to fund acquisitions and other capital commitments.

 

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During the first six months of 2013, we received net cash of $92.8 million from financing activities, including $500 million from the issuance of our senior notes, partially offset by $125 million used to repay in full and terminate our former second lien term loan, net repayments of $193.5 million under our credit agreement, and a $75 million distribution to Holdings’ Class A limited partners.  Net repayments reduced the outstanding borrowings under our credit agreement from $237 million at December 31, 2012 to $43.5 million at June 30, 2013.

 

During the first six months of 2012, we received net cash of $56.0 million from financing activities, consisting primarily of net borrowings under our credit agreement.

 

Liquidity

 

Our primary sources of liquidity historically have been internally generated cash flows, the borrowing capacity under our credit agreement, and partner contributions, including partner contributions from our equity sponsor, the Apollo Funds.  Since we operate a majority of our wells, we also have the ability to adjust our capital expenditures as economic conditions change.  We may use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility.  We believe that our internally generated cash flows and expected future availability under our credit agreement after application of the net proceeds from our IPO will be sufficient to fund our operations and planned capital expenditures for at least the next 12 months.  However, should commodity prices decline for an extended period of time or the capital/credit markets become constrained, the borrowing capacity under our credit agreement could be adversely affected.  In the event of a reduction in the borrowing base under our credit agreement, we may be required to prepay some or all of our indebtedness, which would adversely affect our capital expenditure program.  In addition, because wells funded in the next 12 months represent only a small percentage of our identified net drilling locations, we will be required to generate or raise additional capital to develop our entire inventory of identified drilling locations should we elect to do so.

 

In 2013, we expect our drilling capital expenditures to be between $340 million to $350 million, plus an additional $15 million for leasing, infrastructure, and capital workovers.  The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions.  We plan to finance our ongoing expenditures using internally generated cash flow and availability under our credit agreement.

 

Internally generated cash flows.  Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil, natural gas, and NGL prices.  During the first six months of 2013, our average realized oil and NGL prices decreased by 4% and 23%, respectively, as compared to the first six months of 2012, while our average realized natural gas price increased by 52%.  Realized commodity prices fluctuate widely in response to changing market forces.  If commodity prices decline or we experience a significant widening of our differentials to NYMEX prices, then our results of operations, cash flows from operations, and borrowing base under our credit agreement may be adversely impacted.  Prolonged periods of lower commodity prices or sustained wider differentials to NYMEX prices could cause us to not be in compliance with financial covenants under our credit agreement and thereby affect our liquidity.  To offset reduced cash flows in a lower commodity price environment, we have established a portfolio of commodity derivative contracts consisting primarily of oil swaps that will provide stable cash flows on a portion of our oil production.  As of June 30, 2013, our hedged oil volumes for the remainder of 2013, 2014, and 2015 represent 104%, 115%, and 19%, respectively, of our June 2013 oil production at weighted average prices of $94.93, $92.67, and $93.18, respectively.  An increase in oil prices above the ceiling prices in our commodity derivative contracts limits cash inflows because we would be required to pay our counterparties for the difference between the market price for oil and the ceiling price of the commodity derivative contract resulting in a loss.  Please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our commodity derivative contracts.

 

Credit agreement.  We are a party to an amended and restated credit agreement dated March 19, 2013, which we refer to as our credit agreement, which matures on March 19, 2018.  Our credit agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for the account of us or any of our restricted subsidiaries.  The aggregate amount of the commitments of the lenders under our credit agreement is $1.0 billion.  Availability under our credit agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations.

 

As of June 30, 2013, the borrowing base was $320 million and there were $43.5 million of outstanding borrowings, $276.5 million of borrowing capacity, and no outstanding letters of credit under our credit agreement.  In conjunction with the offering of our senior notes in April 2013 as discussed below, the borrowing base under our credit agreement was reduced to $267.5 million.  We used a portion of the net proceeds from the offering of the senior notes to reduce the outstanding borrowings under our credit

 

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Table of Contents

 

agreement.   In May 2013, we amended our credit agreement to, among other things, increase the borrowing base to $320 million.  As of August 13, 2013, there were no outstanding borrowings under our credit agreement.

 

Obligations under our credit agreement are secured by a first-priority security interest in substantially all of our proved reserves and in the equity interests of our operating subsidiaries.  In addition, obligations under our credit agreement are guaranteed by our operating subsidiaries.

 

Loans under our credit agreement are subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under our credit agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under our credit agreement bear interest at the base rate plus the applicable margin indicated in the following table.  We also incur a quarterly commitment fee on the unused portion of our credit agreement indicated in the following table:

 

Ratio of Outstanding Borrowings to Borrowing Base

 

Unused
Commitment Fee

 

Applicable
Margin for
Eurodollar Loans

 

Applicable
Margin for Base
Rate Loans

 

Less than or equal to .30 to 1

 

0.375

%

1.50

%

0.50

%

Greater than .30 to 1 but less than or equal to .60 to 1

 

0.375

%

1.75

%

0.75

%

Greater than .60 to 1 but less than or equal to .80 to 1

 

0.50

%

2.00

%

1.00

%

Greater than .80 to 1 but less than or equal to .90 to 1

 

0.50

%

2.25

%

1.25

%

Greater than .90 to 1

 

0.50

%

2.50

%

1.50

%

 

 

The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate equal to the LIBOR for deposits in dollars for a similar interest period.  The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5%; or (3) except during a “LIBOR Unavailability Period”, the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0%.

 

Any outstanding letters of credit reduce the availability under our credit agreement.  Borrowings under our credit agreement may be repaid from time to time without penalty.

 

Our credit agreement contains covenants including, among others, the following:

 

·                  a prohibition against incurring debt, subject to permitted exceptions;

·                  a restriction on creating liens on our assets and the assets of our operating subsidiaries, subject to permitted exceptions;

·                  restrictions on merging and selling assets outside the ordinary course of business;

·                  restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

·                  a requirement that we maintain a ratio of consolidated total debt to EBITDAX (as defined in our credit agreement) of not more than 4.75 to 1.0 (which ratio changes to 4.5 to 1.0 beginning with the quarter ended June 30, 2014); and

·                  a provision limiting commodity derivative contracts to a volume not exceeding 85% of projected production from proved reserves for a period not exceeding 66 months from the date the commodity derivative contract is entered into.

 

Our credit agreement contains customary events of default, including our failure to comply with our financial ratios described above, which would permit the lenders to accelerate the debt if not cured within applicable grace periods.  If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under our credit agreement to be immediately due and payable, which would materially and adversely affect our financial condition and liquidity.

 

Certain of the lenders underwriting our credit agreement are also counterparties to our commodity derivative contracts. Please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion.

 

Senior notes.  In April 2013, we issued $500 million aggregate principal amount of 7 3/8% senior notes due 2021.  The net proceeds from the senior notes offering were used to repay a portion of the outstanding borrowings under our credit agreement, to repay in full and terminate our former second lien term loan, to make a $75 million distribution to Holdings Class A limited partners,

 

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and for general partnership purposes.  The indenture governing the senior notes contains covenants, including, among other things, covenants that restrict our ability to:

 

·                  make distributions, investments, or other restricted payments if our fixed charge coverage ratio is less than 2.0 to 1.0;

·                  incur additional indebtedness if our fixed charge coverage ratio would be less than 2.0 to 1.0; and

·                  create liens, sell assets, consolidate or merge with any other person, or engage in transactions with affiliates.

 

These covenants are subject to a number of important qualifications, limitations, and exceptions.  In addition, the indenture contains other customary terms, including certain events of default upon the occurrence of which the senior notes may be declared immediately due and payable.

 

Under the indenture, starting on April 15, 2016, we will be able to redeem some or all of the senior notes at a premium that will decrease over time, plus accrued and unpaid interest to the date of redemption.  Prior to April 15, 2016, we will be able, at our option, to redeem up to 35% of the aggregate principal amount of the senior notes at a price of 107.375% of the principal thereof, plus accrued and unpaid interest to the date of redemption, with an amount equal to the net proceeds from certain equity offerings.  In addition, at our option, prior to April 15, 2016, we may redeem some or all of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes, plus an “applicable premium”, plus accrued and unpaid interest to the date of redemption.  If a change of control occurs on or prior to July 15, 2014, we may redeem all, but not less than all, of the notes at 110% of the principal amount thereof plus accrued and unpaid interest to, but not including, the redemption date.  Certain asset dispositions will be triggering events that may require us to repurchase all or any part of a noteholder’s notes at a purchase price in cash equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to but excluding the date of repurchase. Interest on the senior notes is payable in cash semi-annually in arrears, commencing on October 15, 2013, through maturity.

 

Capitalization.  At June 30, 2013, we had total assets of $1.0 billion and total capitalization of $853.2 million, of which 36% was represented by equity and 64% by long-term debt.  At December 31, 2012, we had total assets of $852.3 million and total capitalization of $782.9 million, of which 54% was represented by equity and 46% by long-term debt.  The percentages of our capitalization represented by equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

 

On August 7, 2013, we completed our IPO of 15,789,474 shares of our common stock at $20.00 per share and received net proceeds of approximately $293.4 million, after deducting underwriting discounts and commissions and estimated offering expenses.  We used the net proceeds from the IPO to purchase New Holdings Units from Holdings.  Holdings used the proceeds it received as a result of our purchase of New Holdings Units (i) to reduce outstanding borrowings under the our credit agreement, (ii) to provide additional liquidity for use in our drilling program, and (iii) for general corporate purposes.  Following the closing of the IPO and repayment of all outstanding borrowings under our credit agreement, we had $233.5 million in cash on hand as of August 7, 2013.  Including the $320 million of undrawn borrowing capacity under our credit agreement, our total liquidity was $553.5 million as of August 7, 2013.

 

Changes in Prices

 

Our revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms are affected by changes in commodity prices, which can fluctuate significantly.  The following table provides our average realized prices for the periods indicated:

 

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Average realized prices:

 

 

 

 

 

 

 

 

 

Oil ($/Bbl) (excluding impact of cash settled derivatives)

 

$

91.80

 

$

85.84

 

$

88.19

 

$

91.82

 

Oil ($/Bbl) (after impact of cash settled derivatives)

 

91.03

 

85.61

 

87.51

 

87.35

 

Natural gas ($/Mcf)

 

3.72

 

2.03

 

3.51

 

2.31

 

NGLs ($/Bbl)

 

27.27

 

34.29

 

29.08

 

37.80

 

Combined ($/BOE) (excluding impact of cash settled derivatives)

 

64.04

 

59.22

 

62.65

 

64.38

 

Combined ($/BOE) (after impact of cash settled derivatives)

 

63.59

 

59.09

 

62.25

 

61.79

 

 

Increases in commodity prices may be accompanied by or result in: (i) increased development costs, as the demand for drilling operations increases; (ii) increased severance taxes, as we are subject to higher severance taxes due to the increased value of hydrocarbons extracted from our wells; and (iii) increased LOE, such as electricity costs, as the demand for services related to the operation of our wells increases.  Decreases in commodity prices can have the opposite impact of those listed above and can result in an impairment charge to our oil and natural gas properties.

 

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Critical Accounting Policies and Estimates

 

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in our final prospectus dated August 1, 2013 and filed with the SEC on August 5, 2013.

 

Income Taxes

 

We account for income taxes using the asset and liability method.  Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax laws and rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

 

We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets, including net operating losses.  In making this determination, we consider all available positive and negative evidence and make certain assumptions.  We consider, among other things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends, and our outlook for future years.  We believe it is more likely than not that certain net operating losses can be carried forward and utilized.

 

In April 2013, we had a corporate reorganization to effectuate our IPO.  Holdings, our accounting predecessor, is a partnership structure not subject to federal income tax.  Pursuant to the steps of the corporate reorganization, the Apollo Funds’ Class A limited partner interests and the Class B limited partner interests of Holdings were exchanged for shares of our common stock.  Our operations are now subject to federal income tax.  The tax implications of the corporate reorganization and the tax impact of the conversion to operating as a taxable entity have been reflected in our consolidated financial statements.

 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

 

The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks.  The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates.  The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure.  This information provides indicators of how we view and manage our ongoing market risk exposures.  We do not enter into market risk sensitive instruments for speculative trading purposes.

 

Derivative policy

 

Due to the volatility of commodity prices, we enter into various derivative instruments to manage and reduce our exposure to price changes.  We primarily utilize WTI crude oil swaps that establish a fixed price for the production covered by the swaps.  We also have employed WTI crude oil options (including puts and collars) to further mitigate our commodity price risk.  All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement.  While this strategy may result in lower net cash inflows in times of higher oil prices than we would otherwise have, had we not utilized these instruments, management believes that the resulting reduced volatility of cash flow resulting from use of derivatives is beneficial.

 

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Counterparties

 

At June 30, 2013, we had committed 10% or greater (in terms of fair market value) of our oil derivative contracts in asset positions to the following counterparties, or one of their affiliates:

 

 

 

Fair Market Value of

 

 

 

Oil Derivative

 

 

 

Contracts

 

Counterparty

 

Committed

 

 

 

(in thousands)

 

BNP Paribas

 

$

3,825

 

Wells Fargo

 

2,318

 

Scotiabank

 

1,474

 

Barclays PLC

 

1,350

 

Royal Bank of Canada

 

1,192

 

 

 

 

 

 

We do not require collateral from our counterparties for entering into financial instruments, so in order to mitigate the credit risk of financial instruments, we enter into master netting agreements with our counterparties.  The master netting agreement is a standardized, bilateral contract between a given counterparty and us.  Instead of treating each financial transaction between the counterparty and us separately, the master netting agreement enables the counterparty and us to aggregate all financial trades and treat them as a single agreement.  This arrangement is intended to benefit us in two ways: (i) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (ii) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.

 

The counterparties to our commodity derivative contracts are composed of six institutions, all of which are rated A- or better by Standard & Poor’s and Baa2 or better by Moody’s and five of which are lenders under our credit agreement.

 

Commodity price sensitivity

 

Commodity prices are often subject to significant volatility due to many factors that are beyond our control, including but not limited to: prevailing economic conditions, supply and demand of hydrocarbons in the marketplace, actions by speculators, and geopolitical events such as wars or natural disasters.  We manage oil price risk with swaps, puts, and collars. Swaps provide a fixed price for a notional amount of sales volumes.  Puts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price.  Collars provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.  This participation is limited by a ceiling price specified in the contract.

 

The following table summarizes our open commodity derivative contracts as of June 30, 2013:

 

 

 

Average

 

Weighted -

 

Average

 

Weighted -

 

Average

 

Weighted -

 

Asset

 

 

 

Daily

 

Average

 

Daily

 

Average

 

Daily

 

Average

 

(Liability)

 

 

 

Floor

 

Floor

 

Cap

 

Cap

 

Swap

 

Swap

 

Fair Market

 

Period

 

Volume

 

Price

 

Volume

 

Price

 

Volume

 

Price

 

Value

 

 

 

(Bbl)

 

(per Bbl)

 

(Bbl)

 

(per Bbl)

 

(Bbl)

 

(per Bbl)

 

(in thousands)

 

July - Dec. 2013

 

150

 

$

75.00

 

150

 

$

105.95

 

6,750

(a)

$

94.93

 

$

(208

)

2014

 

 

 

 

 

7,950

 

92.67

 

7,711

 

2015

 

 

 

 

 

1,300

 

93.18

 

3,536

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

11,039

 

 


(a)         Includes 6,500 Bbls/D at $94.85 per Bbl for the third quarter of 2013 and 7,000 Bbls/D at $95.01 per Bbl for the fourth quarter of 2013.

 

We are also a party to Midland-Cushing basis differential swaps for 5,000 Bbls/D at $1.20/Bbl for July through December 2013.  At June 30, 2013, the fair value of these contracts was a liability of approximately $0.9 million.

 

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As of June 30, 2013, the fair market value of our oil derivative contracts was a net asset of $10.1 million.  Based on our open commodity derivative positions at June 30, 2013, a 10% increase in NYMEX prices for oil would change our net commodity derivative asset to a net commodity derivative liability of approximately $31.5 million, while a 10% decrease in NYMEX prices for oil would increase our net commodity derivative asset by approximately $41.5 million.

 

Interest rate sensitivity

 

At June 30, 2013, we had outstanding debt of $543.5 million, $500 million of which bears interest at a fixed rate of 7 3/8% and $43.5 million of which consisted of outstanding borrowings under our credit agreement and is subject to floating market rates of interest that are linked to the Eurodollar rate.  At this level of floating rate debt, if the Eurodollar rate increased 10%, we would incur an additional $74,000 of interest expense per year, and if the Eurodollar rate decreased 10%, we would incur $74,000 less.  Additionally, if the market price of our senior notes increased by 10%, the fair value at June 30, 2013 would increase from approximately $497.6 million to approximately $547.3 million, and if the market price decreased by 10%, the fair value would decrease to approximately $447.8 million.

 

Item 4.  Controls and Procedures

 

In accordance with the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2013 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

 

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose.  However, we are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which requires our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of its internal control over financial reporting.  We will not be required to make our first assessment of internal control over financial reporting under Section 404 until the year following our first annual report required to be filed with the SEC.

 

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Table of Contents

 

PART II. OTHER INFORMATION

 

Item 1.  Legal Proceedings

 

From time to time, we are a party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment related disputes.  We do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations, or liquidity.

 

Item 1A.  Risk Factors

 

In addition to the other information set forth in this Report, you should carefully consider the factors discussed in “Risk Factors” in our final prospectus dated August 1, 2013 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933 on August 5, 2013, which could materially affect our business, financial condition, and/or future results.  The risks described in our final prospectus are not the only risks we face.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.

 

Item 2.  Unregistered Sales of Securities and Use of Proceeds

 

Unregistered Sales of Securities

 

In connection with our incorporation on April 1, 2013 under the laws of the State of Delaware, we issued 1,000 shares of our common stock to Athlon Holdings GP LLC for an aggregate purchase price of $10.00.  These securities were offered and sold by us in reliance upon the exemption from the registration requirements provided by Section 4(2) of the Securities Act.

 

On April 26, 2013, in connection with our reorganization transactions, certain holders of interests in Holdings exchanged their Class A limited partner interests and Class B interests of Holdings for an aggregate of 960,907 shares of our common stock.  These securities were issued by us in reliance upon the exemption from the registration requirements provided by Section 4(2) of the Securities Act.

 

Use of Proceeds

 

On August 1, 2013, we priced our IPO of 15,789,474 shares of common stock at a price to the public of $20.00 per share.  The IPO was made pursuant to a registration statement on Form S-1 (File No. 333-189109) that was declared effective by the SEC on August 1, 2013.  Citigroup Global Markets Inc., Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith, Inc., UBS Securities LLC, Wells Fargo Securities, LLC, Apollo Global Securities, LLC, RBC Capital Markets, LLC, Scotia Capital (USA) Inc., Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Tudor, Pickering, Holt & Co. Securities, Inc., Credit Agricole Securities (USA) Inc., Mitsubishi UFJ Securities (USA), Inc., Simmons & Company International, Stephens Inc., CIBC World Markets Corp., FBR Capital Markets & Co., and Lebenthal & Co. served as the underwriters to our IPO.

 

Net proceeds from the sale of the shares of common stock were approximately $293.4 million, after deducting the underwriters’ discounts and commissions of $17.4 million, in the aggregate, and estimated offering expenses of approximately $5.0 million.  We used the net proceeds from the IPO to purchase newly issued New Holdings Units from Holdings, which subsequently used the net proceeds to repay outstanding indebtedness under our credit agreement, provide additional liquidity for use in our drilling program, and for general corporate purposes.

 

Item 6.  Exhibits

 

Exhibit No.

 

Description

 

 

 

3.1*

 

Amended and Restated Certificate of Incorporation of Athlon Energy Inc.

3.2*

 

Amended and Restated Bylaws of Athlon Energy Inc.

31.1*

 

Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer).

31.2*

 

Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer).

32.1*

 

Section 1350 Certification (Principal Executive Officer).

32.2*

 

Section 1350 Certification (Principal Financial Officer).

101.INS**

 

XBRL Instance Document.

 

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101.SCH**

 

XBRL Taxonomy Extension Schema Document.

101.CAL**

 

XBRL Taxonomy Extension Calculation Linkbase.

101.DEF**

 

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB**

 

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE**

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 


*                                         Filed herewith.

**                                  To be filed by amendment during the 30-day grace period provided by Rule 405(a)(2) of Regulation S-T.  Pursuant to Rule 406T of Regulation S-T, these interactive data files will be furnished and will not be deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, will not be deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

 

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Table of Contents

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

ATHLON ENERGY INC.

 

 

 

 

 

/s/ William B. D. Butler

 

William B. D. Butler

 

Vice President—Chief Financial Officer and

 

Principal Financial Officer

 

 

 

 

 

/s/ John C. Souders

 

John C. Souders

 

Vice President—Controller and

 

Principal Accounting Officer

 

 

Date: August 14, 2013

 

 

39