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EXCEL - IDEA: XBRL DOCUMENT - Approach Resources IncFinancial_Report.xls

 

 

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 September 30, 2013

OR

 

¨ 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: 001-33801

 

 

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   51-0424817

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

One Ridgmar Centre

6500 West Freeway, Suite 800

Fort Worth, Texas

  76116
(Address of principal executive offices)   (Zip Code)

(817) 989-9000

(Registrant’s telephone number, including area code)

N/A

(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.    x  Yes    ¨  No

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

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

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if smaller reporting company)    Smaller reporting company   ¨

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

The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of October 31, 2013, was 39,021,886.

 

 

 


PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

Approach Resources Inc. and Subsidiaries

Unaudited Consolidated Balance Sheets

(In thousands, except shares and per-share amounts)

 

     September 30,     December 31,  
     2013     2012  
ASSETS   

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 25,489      $ 767   

Accounts receivable:

    

Joint interest owners

     210        215   

Oil, NGL and gas sales

     15,210        12,575   

Unrealized gain on commodity derivatives

     1,387        1,552   

Prepaid expenses and other current assets

     357        547   

Deferred income taxes – current

     163        —     
  

 

 

   

 

 

 

Total current assets

     42,816        15,656   

PROPERTIES AND EQUIPMENT:

    

Oil and gas properties, at cost, using the successful efforts method of accounting

     1,245,360        1,025,440   

Furniture, fixtures and equipment

     2,502        2,108   
  

 

 

   

 

 

 
     1,247,862        1,027,548   

Less accumulated depletion, depreciation and amortization

     (253,788     (199,081
  

 

 

   

 

 

 

Net properties and equipment

     994,074        828,467   

Equity method investment

     18,331        9,892   

Unrealized gain on commodity derivatives

     326        881   

Other assets

     8,217        843   
  

 

 

   

 

 

 

Total assets

   $ 1,063,764      $ 855,739   
  

 

 

   

 

 

 
LIABILITIES AND STOCKHOLDERS’ EQUITY   

CURRENT LIABILITIES:

    

Accounts payable

   $ 40,692      $ 24,916   

Oil, NGL and gas sales payable

     5,451        4,960   

Deferred income taxes – current

     —          531   

Accrued liabilities

     57,043        29,840   

Unrealized loss on commodity derivatives

     2,242        —     
  

 

 

   

 

 

 

Total current liabilities

     105,428        60,247   

NON-CURRENT LIABILITIES:

    

Senior secured credit facility

     —          106,000   

Senior notes

     250,000        —     

Unrealized loss on commodity derivatives

     285        —     

Deferred income taxes

     53,586        48,593   

Asset retirement obligations

     8,091        7,431   
  

 

 

   

 

 

 

Total liabilities

     417,390        222,271   

COMMITMENTS AND CONTINGENCIES

    

STOCKHOLDERS’ EQUITY :

    

Preferred stock, $0.01 par value, 10,000,000 shares authorized none outstanding

     —          —     

Common stock, $0.01 par value, 90,000,000 shares authorized 39,022,623 and 38,829,368 issued and outstanding, respectively

     390        388   

Additional paid-in capital

     565,437        560,468   

Retained earnings

     80,547        72,612   
  

 

 

   

 

 

 

Total stockholders’ equity

     646,374        633,468   
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 1,063,764      $ 855,739   
  

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

1


Approach Resources Inc. and Subsidiaries

Unaudited Consolidated Statements of Operations

(In thousands, except shares and per-share amounts)

 

    Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
    2013     2012     2013     2012  

REVENUES:

       

Oil, NGL and gas sales

  $ 44,196      $ 33,038      $ 122,737      $ 93,583   

EXPENSES:

       

Lease operating

    4,370        5,468        13,746        13,286   

Production and ad valorem taxes

    3,167        2,341        8,791        6,807   

Exploration

    1,193        1,170        2,010        2,419   

General and administrative

    6,171        5,633        17,810        16,448   

Depletion, depreciation and amortization

    19,413        16,728        54,951        42,354   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

    34,314        31,340        97,308        81,314   
 

 

 

   

 

 

   

 

 

   

 

 

 

OPERATING INCOME

    9,882        1,698        25,429        12,269   

OTHER:

       

Interest expense, net

    (5,179     (1,544     (8,859     (3,811

Equity in income of investee

    340        —          160        —     

Realized (loss) gain on commodity derivatives

    (840     423        (1,247     300   

Unrealized (loss) gain on commodity derivatives

    (3,438     (4,185     (3,248     2,582   
 

 

 

   

 

 

   

 

 

   

 

 

 

INCOME (LOSS) BEFORE INCOME TAX PROVISION (BENEFIT)

    765        (3,608     12,235        11,340   

INCOME TAX PROVISION (BENEFIT)

    270        (1,253     4,300        4,119   
 

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS)

  $ 495      $ (2,355   $ 7,935      $ 7,221   
 

 

 

   

 

 

   

 

 

   

 

 

 

EARNINGS (LOSS) PER SHARE:

       

Basic

  $ 0.01      $ (0.07   $ 0.20      $ 0.21   
 

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

  $ 0.01      $ (0.07   $ 0.20      $ 0.21   
 

 

 

   

 

 

   

 

 

   

 

 

 

WEIGHTED AVERAGE SHARES OUTSTANDING:

       

Basic

    39,011,555        34,190,192        38,980,971        33,656,726   

Diluted

    39,032,813        34,190,192        39,002,731        33,736,119   

See accompanying notes to these consolidated financial statements.

 

2


Approach Resources Inc. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

(In thousands)

 

     Nine Months Ended  
     September 30,  
     2013     2012  

OPERATING ACTIVITIES:

    

Net income

   $ 7,935      $ 7,221   

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

    

Depletion, depreciation and amortization

     54,951        42,354   

Unrealized loss (gain) on commodity derivatives

     3,248        (2,582

Exploration expense

     2,010        2,419   

Share-based compensation expense

     5,389        4,993   

Deferred income taxes

     4,300        4,119   

Equity in income of investee

     (160     —     

Changes in operating assets and liabilities:

    

Accounts receivable

     (2,630     (1,968

Prepaid expenses and other assets

     959        414   

Accounts payable

     15,300        16,263   

Oil, NGL and gas sales payable

     491        (319

Accrued liabilities

     27,203        3,550   
  

 

 

   

 

 

 

Cash provided by operating activities

     118,996        76,464   
  

 

 

   

 

 

 

INVESTING ACTIVITIES:

    

Additions to oil and gas properties

     (221,514     (224,971

Contribution to equity method investment

     (8,279     —     

Additions to other property and equipment, net

     (394     (464
  

 

 

   

 

 

 

Cash used in investing activities

     (230,187     (225,435
  

 

 

   

 

 

 

FINANCING ACTIVITIES:

    

Proceeds from issuance of common stock, net of offering costs

     —          144,988   

Borrowings under senior secured credit facility, net of debt issuance costs

     129,059        214,025   

Repayment of amounts outstanding under senior secured credit facility

     (235,950     (210,300

Proceeds from issuance of senior notes

     242,746        —     

Proceeds from issuance of common stock upon exercise of stock options

     58        798   
  

 

 

   

 

 

 

Cash provided by financing activities

     135,913        149,511   
  

 

 

   

 

 

 

CHANGE IN CASH AND CASH EQUIVALENTS

     24,722        540   

CASH AND CASH EQUIVALENTS, beginning of period

   $ 767      $ 301   
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS, end of period

   $ 25,489      $ 841   
  

 

 

   

 

 

 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

    

Cash paid for interest

   $ 3,045      $ 3,341   
  

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

3


Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2013

1. Summary of Significant Accounting Policies

Organization and Nature of Operations

Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on finding and developing oil and gas reserves in shale oil and tight sands. Our properties are primarily located in the Permian Basin in West Texas.

During 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which transports our oil to market. In October 2012, we made an initial contribution of $10 million to the joint venture for pipeline and facilities construction. During the nine months ended September 30, 2013, we made additional contributions of $8.3 million. Our contributions are recorded at cost and are included in noncurrent assets, “Equity method investment,” on our consolidated balance sheets and in investing activities, “Contribution to equity method investment,” on our consolidated statements of cash flows. On September 18, 2013, Approach, together with our partner in the joint venture, entered into a definitive agreement to sell all of the equity interest of the joint venture. We completed this sale on October 7, 2013, and net proceeds at closing totaled approximately $109.1 million, after deducting our share of transactional costs paid at closing. We estimate that we will recognize a pre-tax gain of approximately $91 million in fourth quarter 2013 related to this sale. In connection with the closing of the Wildcat sale, we also entered into an amendment to our crude oil purchase agreement with Wildcat.

Consolidation, Basis of Presentation and Significant Estimates

The interim consolidated financial statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year due in part to the volatility in prices for oil, NGLs and gas, future commodity prices for commodity derivative contracts, global economic and financial market conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks, geological risks, transportation restrictions, timing of acquisitions, product supply and demand, market competition and interruptions of production. You should read these consolidated interim financial statements in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the Securities and Exchange Commission on February 28, 2013.

The accompanying interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, we have made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and gas reserves, which affect the amount at which oil and gas properties are recorded. Significant assumptions are also required in estimating our accrual of capital expenditures, asset retirement obligations, share-based compensation and income taxes. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior year amounts have been reclassified to conform to current year presentation. These classifications have no impact on the net income reported.

 

4


Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2013

 

2. Earnings Per Common Share

We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The following table provides a reconciliation of the numerators and denominators of our basic and diluted earnings per share (dollars in thousands, except per-share amounts).

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2013      2012     2013      2012  

Income (numerator):

          

Net income (loss) – basic

   $ 495       $ (2,355   $ 7,935       $ 7,221   
  

 

 

    

 

 

   

 

 

    

 

 

 

Weighted average shares (denominator):

          

Weighted average shares – basic

     39,011,555         34,190,192        38,980,971         33,656,726   

Dilution effect of share-based compensation, treasury method

     21,258         —   (1)      21,760         79,393   
  

 

 

    

 

 

   

 

 

    

 

 

 

Weighted average shares – diluted

     39,032,813         34,190,192        39,002,731         33,736,119   
  

 

 

    

 

 

   

 

 

    

 

 

 

Net (loss) income per share:

          

Basic

   $ 0.01       $ (0.07   $ 0.20       $ 0.21   
  

 

 

    

 

 

   

 

 

    

 

 

 

Diluted

   $ 0.01       $ (0.07   $ 0.20       $ 0.21   
  

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) Approximately 25,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the three months ended September 30, 2012.

3. Long-Term Debt

The following table provides a summary of our long-term debt at September 30, 2013, and December 31, 2012 (in thousands).

 

     September 30,      December 31,  
     2013      2012  

Credit Facility

   $ —         $ 106,000   

Senior Notes

     250,000         —     
  

 

 

    

 

 

 

Total long-term debt

   $ 250,000       $ 106,000   
  

 

 

    

 

 

 

Credit Facility

Our credit facility (as amended, the “Credit Facility”) has a maturity date of July 31, 2016. At September 30, 2013, our borrowing base was $315 million, with maximum commitments from the lenders in the Credit Facility of $500 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil, NGL and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year.

Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.75% to 1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment of 0.50% of unused borrowings available under our Credit Facility.

On November 6, 2013, we entered into a sixteenth amendment to the Credit Facility, which, among other things, increased the borrowing base to $350 million from $315 million.

 

5


Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2013

 

We had no outstanding borrowings under our Credit Facility at September 30, 2013, compared to outstanding borrowings of $106 million at December 31, 2012. The weighted average interest rate applicable to borrowings under our Credit Facility at December 31, 2012, was 2.7%. We also had outstanding unused letters of credit under our Credit Facility totaling $325,000 at September 30, 2013, which reduce amounts available for borrowing under our Credit Facility.

Loans under our Credit Facility are secured by first priority liens on substantially all of our West Texas assets and are guaranteed by certain of our subsidiaries.

Covenants

Our Credit Facility contains two principal financial covenants:

 

    a consolidated modified current ratio covenant that requires us to maintain a ratio of not less than 1.0 to 1.0 at all times. The consolidated modified current ratio is calculated by dividing consolidated current assets (as defined in the Credit Facility) by consolidated current liabilities (as defined in the Credit Facility). As defined more specifically in the Credit Facility, the consolidated modified current ratio is calculated as current assets less current unrealized gains on commodity derivatives plus the available borrowing base at the respective balance sheet date, divided by current liabilities less current unrealized losses on commodity derivatives at the respective balance sheet date.

 

    a consolidated funded debt-to-consolidated EBITDAX ratio covenant that requires us to maintain a ratio of not more than 4.0 to 1.0 at the end of each fiscal quarter. The consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing consolidated funded debt (as defined in the Credit Facility) by consolidated EBITDAX (as defined in the Credit Facility). As defined more specifically in the Credit Facility, consolidated EBITDAX is calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, (6) income and franchise taxes and (7) certain other noncash expenses, less (1) gains or losses from sales or dispositions of assets, (2) unrealized gain on commodity derivatives and (3) extraordinary or nonrecurring gains. For purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the Credit Facility.

Our Credit Facility also restricts cash dividends and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investments in other entities and liens on properties.

In addition, our Credit Facility contains customary events of default that would permit our lenders to accelerate the debt under our Credit Facility if not cured within applicable grace periods, including, among others, failure to make payments of principal or interest when due, materially incorrect representations and warranties, failure to make mandatory prepayments in the event of borrowing base deficiencies, breach of covenants, defaults upon other obligations in excess of $500,000, events of bankruptcy, the occurrence of one or more unstayed judgments in excess of $500,000 not covered by an acceptable policy of insurance, failure to pay any obligation in excess of $500,000 owed under any derivatives transaction or in any amount if the obligation under the derivatives transaction is secured by collateral under the Credit Facility, any event of default by the Company occurs under any agreement entered into in connection with a derivatives transaction, liens securing the loans under the credit agreement cease to be in place, a change in control (as defined under the Credit Facility) of the Company occurs, and dissolution of the Company.

 

6


Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2013

 

Senior Notes

In June 2013, we completed our public offering of $250 million principal amount of 7% senior notes due 2021 (the “Senior Notes”). Interest on the Senior Notes is payable semi-annually on June 15 and December 15, beginning December 15, 2013. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under our Credit Facility.

We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wells Fargo Bank, National Association, as trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.”

On and after June 15, 2016, we may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. Before June 15, 2016, we may redeem up to 35% of the Senior Notes at a redemption price of 107% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. In addition, before June 15, 2016, we may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the Senior Notes from holders. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries.

The Indenture restricts our ability, among other things, to (i) sell assets, (ii) pay distributions on, redeem or repurchase, equity interests, (iii) incur additional debt, (iv) make certain investments, (v) enter into transactions with affiliates, (v) incur liens and (vi) merge or consolidate with another company. These restrictions are subject to a number of important exceptions and qualifications. If at any time the Senior Notes are rated investment grade by both Moody’s Investors Service and Standard & Poor’s Ratings Services and no default (as defined in the Indenture) has occurred and is continuing, many of these restrictions will terminate. The Indenture contains customary events of default.

At September 30, 2013, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

Subsidiary Guarantors

The Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. Approach Resources Inc. is a holding company with no independent assets or operations. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no significant restrictions on the Company’s ability, or the ability of any subsidiary guarantor, to obtain funds from its subsidiaries through dividends, loans, advances or otherwise.

4. Commitments and Contingencies

Our contractual obligations include long-term debt, daywork drilling contracts, operating lease obligations, asset retirement obligations and employment agreements with our executive officers. Since December 31, 2012, there have been no material changes to our contractual obligations, other than an increase in long-term debt, primarily due to the issuance of the Senior Notes as discussed in Note 3 above. In connection with the issuance of the Senior Notes, our annual interest expense related to the Senior Notes is $17.5 million due semi-annually on June 15 and December 15, beginning December 15, 2013.

 

7


Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2013

 

We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows.

5. Income Taxes

The effective income tax rate for the three and nine months ended September 30, 2013, was 35.3% and 35.1%, respectively. Total income tax expense for the three and nine months ended September 30, 2013, differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to state taxes and the impact of permanent differences between book and taxable income.

The effective income tax rate for the three and nine months ended September 30, 2012, was 34.7% and 36.3%, respectively. Total income tax expense differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to state taxes and the impact of permanent differences between book and taxable income.

6. Fair Value of Financial and Derivative Instruments

At September 30, 2013, we had the following commodity derivatives positions outstanding:

 

Commodity and Period

   Contract
Type
   Volume Transacted    Contract Price

Crude Oil

  

2013

   Collar    650 Bbls/d    $90.00/Bbl – $105.80/Bbl

2013

   Collar    450 Bbls/d    $90.00/Bbl – $101.45/Bbl

2013 (1)

   Collar    1,200 Bbls/d    $90.35/Bbl – $100.35/Bbl

2014

   Collar    550 Bbls/d    $90.00/Bbl – $105.50/Bbl

2014

   Collar    950 Bbls/d    $85.05/Bbl – $95.05/Bbl

2015

   Collar    2,600 Bbls/d    $84.00/Bbl – $91.00/Bbl

Crude Oil Basis Differential (Midland/Cushing)

        

2013 (2)

   Swap    2,300 Bbls/d    $1.10/Bbl

2014

   Swap    1,500 Bbls/d    $0.55/Bbl

Natural Gas Liquids

        

Propane 2013 (3)

   Swap    550 Bbls/d    $42.00/Bbl

Propane 2014

   Swap    500 Bbls/d    $41.16/Bbl

Natural Gasoline 2013 (3)

   Swap    200 Bbls/d    $90.72/Bbl

Natural Gasoline 2014

   Swap    175 Bbls/d    $83.37/Bbl

Natural Gas

        

2013

   Swap    200,000 MMBtu/month    $3.54/MMBtu

2013

   Swap    190,000 MMBtu/month    $3.80/MMBtu

2013 (4)

   Collar    100,000 MMBtu/month    $4.00/MMBtu – $4.36/MMBtu

2014

   Swap    360,000 MMBtu/month    $4.18/MMBtu

 

(1) February 2013 – December 2013
(2) March 2013 – December 2013
(3) September 2013 – December 2013
(4) May 2013 – December 2013

 

8


Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2013

 

Subsequent to September 30, 2013, we entered into a natural gas swap covering 200,000 MMBtu per month for 2015 at a contract price of $4.10/MMBtu.

The following table summarizes the fair value of our open commodity derivatives as of September 30, 2013, and December 31, 2012 (in thousands).

 

    Asset/Liability Derivatives  
        Fair Value  
        September 30,     December 31,  
   

Balance Sheet Location

  2013     2012  

Derivatives not designated as hedging instruments

     

Commodity derivatives

 

Unrealized (loss) gain on commodity derivatives

  $ (814   $ 2,433   

The following table summarizes the change in the fair value of our commodity derivatives (in thousands).

 

          Three Months Ended     Nine Months Ended  
          September 30,     September 30,  
    

Income Statement Location

   2013     2012     2013     2012  

Derivatives not designated as hedging instruments

           

Commodity derivatives

  

Realized (loss) gain on commodity derivatives

   $ (840   $ 423      $ (1,247   $ 300   
  

Unrealized (loss) gain on commodity derivatives

     (3,438     (4,185     (3,248     2,582   
     

 

 

   

 

 

   

 

 

   

 

 

 
      $ (4,278   $ (3,762   $ (4,495   $ 2,882   
     

 

 

   

 

 

   

 

 

   

 

 

 

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivatives contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.

To estimate the fair value of our commodity derivatives positions, we use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that 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 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

 

9


Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

September 30, 2013

 

    Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At September 30, 2013, we had no Level 1 measurements.

 

    Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At September 30, 2013, all of our commodity derivatives were valued using Level 2 measurements.

 

    Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At September 30, 2013, we had no Level 3 measurements.

Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands).

 

     September 30, 2013  
     Carrying
Amount
     Fair Value  

Senior Notes

   $ 250,000       $ 251,250   
  

 

 

    

 

 

 

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy.

7. Share-Based Compensation

In February 2013, we awarded an aggregate of 183,672 restricted shares to our executive officers. Approximately 25% of the total award is made up of restricted shares subject to three-year total stockholder return (“TSR”) performance conditions, assuming target TSR is achieved. If maximum TSR is achieved, then approximately 33% of the total award will be made up of TSR restricted shares. The remaining restricted shares are performance-based awards with service-based vesting restrictions. The number of shares awarded assumes that the Company will achieve maximum TSR performance conditions. The aggregate fair market value of these shares on the grant date was $4.5 million, to be expensed over a remaining service period of approximately four years, subject to three-year TSR and other performance conditions. We recognized $1.1 million in share-based compensation expense related to these grants during the nine months ended September 30, 2013.

 

10


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

The following discussion is intended to assist in understanding our results of operations and our financial condition. This section should be read in conjunction with management’s discussion and analysis contained in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the Securities and Exchange Commission (“SEC”) on February 28, 2013. Our consolidated financial statements and the accompanying notes included elsewhere in this Quarterly Report on Form 10-Q contain additional information that should be referred to when reviewing this material. Certain statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed in this report. A glossary containing the meaning of the oil and gas industry terms used in this management’s discussion and analysis follows the “Results of Operations” table in this Item 2.

Cautionary Statement Regarding Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The forward-looking statements may include projections and estimates concerning the timing and success of specific projects, typical well economics and our future reserves, production, revenues, costs, income, capital spending, 3-D seismic operations, interpretation and results and obtaining permits and regulatory approvals. When used in this report, the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” “potential” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. We caution all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed or referred to in the “Risk Factors” section and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We expressly disclaim all responsibility to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

 

    uncertainties in drilling, exploring for and producing oil and gas;

 

    uncertainty of commodity prices for oil, NGLs and gas;

 

    overall United States and global economic and financial market conditions;

 

    domestic and foreign demand and supply for oil, NGLs, gas and the products derived from such hydrocarbons;

 

    our inability to obtain additional financing necessary to fund our operations and capital expenditures and to meet our other obligations;

 

11


    the effects of government regulation and permitting and other legal requirements, including laws or regulations that could restrict or prohibit hydraulic fracturing;

 

    disruption of credit and capital markets;

 

    our financial position;

 

    our cash flows and liquidity;

 

    disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, NGLs and gas and other processing and transportation considerations;

 

    marketing of oil, NGLs and gas;

 

    high costs, shortages, delivery delays or unavailability of drilling and completion equipment, materials, labor or other services;

 

    competition in the oil and gas industry;

 

    uncertainty regarding our future operating results;

 

    interpretation of 3-D seismic data;

 

    replacing our oil, NGL and gas reserves;

 

    our ability to retain and attract key personnel;

 

    our business strategy, including our ability to recover oil, NGLs and gas in place associated with our Wolfcamp oil shale resource play in the Permian Basin;

 

    development of our current asset base or property acquisitions;

 

    estimated quantities of oil, NGL and gas reserves;

 

    plans, objectives, expectations and intentions contained in this report that are not historical; and

 

    other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 28, 2013, and in our Quarterly Report on Form 10-Q for the period ended June 30, 2013, filed with the SEC on August 2, 2013.

Overview

Approach Resources Inc. is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on oil and gas reserves in shale oil and tight gas sands in the Midland Basin of the greater Permian Basin in West Texas, where we lease approximately 149,000 net acres. Our drilling targets include the Clearfork, Wolfcamp shale, Canyon Sands, Strawn and Ellenburger zones. We sometimes refer to the Clearfork and Wolfcamp zones together as the “Wolffork,” and our development project in the Permian Basin as “Project Pangea,” which includes the northwestern portion of Project Pangea that we refer to as “Pangea West.” Our management and technical team have a proven track record of finding and developing reserves through advanced drilling and completion techniques. As the operator of all of our estimated proved reserves and production, we have a high degree of control over capital expenditures and other operating matters.

At December 31, 2012, our estimated proved reserves were 95.5 MMBoe, made up of 39% oil, 30% NGLs and 31% natural gas and 34% proved developed. At such date, approximately 99.9% of our proved reserves were located in the Permian Basin in Crockett and Schleicher Counties, Texas. At September 30, 2013, we owned working interests in 694 producing oil and gas wells.

Third Quarter 2013 Activity

During the three months ended September 30, 2013, we produced 812 MBoe, or 8.8 MBoe/d. During the three months ended September 30, 2013, we drilled 12 wells and completed 14 wells. At September 30, 2013, seven horizontal wells were in progress or waiting on completion. We currently have three horizontal rigs running in Project Pangea.

 

12


Sale of Interest in Southern Midland Basin Oil Pipeline

In September 2013, Approach, together with our partner in Wildcat Permian Services LLC (“Wildcat”), entered into a definitive agreement to sell all of the equity interests of Wildcat for a purchase price of $210 million, subject to customary post-closing conditions, adjustments and escrows. Wildcat owns and operates an oil pipeline system in Crockett and Reagan Counties, Texas. We completed the sale of Wildcat in October 2013, and net proceeds to Approach at closing totaled approximately $109.1 million, after deducting our share of transactional costs paid at closing. We estimate that we will recognize a pre-tax gain of approximately $91 million in the fourth quarter of 2013 related to this transaction.

In connection with the closing of the Wildcat sale, in October 2013, we entered into an amendment to our crude oil purchase agreement with Wildcat. The amendment, among other things, amends the dedicated area to include certain areas of Crockett and Schleicher Counties, Texas; amends the transportation and marketing fee; provides for the right and obligations of Approach and Wildcat relating to the construction of future gathering lines and connection facilities; provides us with priority and preference rights for crude oil capacity on the pipeline system; provides for trucking fees for any crude oil transported by truck; and provides for an unconditional guarantee by Wildcat’s parent of all of Wildcat’s obligations and liabilities under the crude oil purchase agreement.

Capital Expenditures

For the three months ended September 30, 2013, our capital expenditures totaled $102 million, consisting of $84.4 million for drilling and completion activities, $11.8 million for pipeline, infrastructure projects and other equipment and $5.8 million for property and acreage acquisitions and lease extensions, including $5 million paid to the Board for Lease of University Lands (“University Lands”) in third quarter 2013 in connection with a Consolidated Drilling and Development Unit Agreement, which extended 60 of our leases with University Lands to September 2017. Also, in third quarter 2013, we made a capital contribution to our pipeline joint venture of $2 million for oil pipeline and facilities construction. Total capital expenditures in 2013 are expected to be $300 million.

Our preliminary estimated drilling and completion capital expenditures for 2014 are expected to be approximately $400 million. Our capital budgets exclude future acquisitions and lease extensions, and are subject to change depending upon a number of factors, including additional data on our Wolfcamp shale oil resource play, results of horizontal drilling and completions, including pad drilling, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and gas, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

 

13


Results of Operations

The following table sets forth summary information regarding oil, NGL and gas revenues, production, average product prices and average production costs and expenses for the three and nine months ended September 30, 2013 and 2012. We determine a barrel of oil equivalent using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGLs may differ significantly from the price for a barrel of oil.

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
     2013     2012      2013     2012  

Revenues (in thousands):

         

Oil

   $ 31,708      $ 21,575       $ 87,551      $ 58,689   

NGLs

     7,231        7,143         19,682        23,797   

Gas

     5,257        4,320         15,504        11,097   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total oil, NGL and gas sales

     44,196        33,038         122,737        93,583   

Realized (loss) gain on commodity derivatives

     (840     423         (1,247     300   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total oil, NGL and gas sales including derivative impact

   $ 43,356      $ 33,461       $ 121,490      $ 93,883   
  

 

 

   

 

 

    

 

 

   

 

 

 

Production:

         

Oil (MBbls)

     314        250         969        670   

NGLs (MBbls)

     242        234         682        672   

Gas (MMcf)

     1,538        1,580         4,393        4,567   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total (MBoe)

     812        747         2,383        2,103   

Total (MBoe/d)

     8.8        8.1         8.7        7.7   

Average prices:

         

Oil (per Bbl)

   $ 101.02      $ 86.38       $ 90.39      $ 87.57   

NGLs (per Bbl)

     29.87        30.50         28.84        35.41   

Gas (per Mcf)

     3.42        2.73         3.53        2.43   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total (per Boe)

   $ 54.41      $ 44.21       $ 51.50      $ 44.49   

Realized (loss) gain on commodity derivatives (per Boe)

     (1.03     0.57         (0.52     0.14   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total including derivative impact (per Boe)

   $ 53.38      $ 44.78       $ 50.98      $ 44.63   

Costs and expenses (per Boe):

         

Lease operating

   $ 5.38      $ 7.32       $ 5.77      $ 6.32   

Production and ad valorem taxes

     3.90        3.13         3.69        3.24   

Exploration

     1.47        1.57         0.84        1.15   

General and administrative

     7.60        7.54         7.47        7.82   

Depletion, depreciation and amortization

     23.91        22.39         23.06        20.14   

 

Glossary

Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to reference oil, condensate or NGLs.

Boe. Barrel of oil equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil equivalent, and one Bbl of NGLs to one Bbl of oil equivalent.

MBbl. Thousand barrels of oil, condensate or NGLs.

 

14


MBoe. Thousand barrels of oil equivalent.

Mcf. Thousand cubic feet of natural gas.

MMBoe. Million barrels of oil equivalent.

MMcf. Million cubic feet of natural gas.

NGLs. Natural gas liquids.

/d. “Per day” when used with volumetric units or dollars.

Three Months Ended September 30, 2013, Compared to Three Months Ended September 30, 2012

Oil, NGL and gas sales. Oil, NGL and gas sales increased $11.2 million, or 34%, for the three months ended September 30, 2013, to $44.2 million, from $33 million for the three months ended September 30, 2012. Of the $11.2 million increase in oil, NGL and gas sales, approximately $6.6 million was attributable to an increase in production volumes and $4.6 million was attributable to an increase in oil, NGL and gas prices. Subject to commodity prices and future curtailments beyond our control, we expect our oil, NGL and gas sales to increase during the remainder of 2013 due to increased production volumes from our development project in the Permian Basin.

Net income (loss). Net income for the three months ended September 30, 2013, was $495,000, or $0.01 per diluted share, compared to a net loss of $2.4 million, or $0.07 per diluted share, for the three months ended September 30, 2012. Net income for the three months ended September 30, 2013, included an unrealized loss on commodity derivatives of $3.4 million and a realized loss on commodity derivatives of $840,000. Net income in the 2013 period increased due to higher revenues and lower lease operating expenses, partially offset by higher interest expense, depletion, depreciation and amortization expense and losses on both our realized and unrealized commodity derivatives.

Oil, NGL and gas production. Production for the three months ended September 30, 2013, totaled 812 MBoe (8.8 MBoe/d), compared to production of 747 MBoe (8.1 MBoe/d) in the prior year period, a 9% increase. Production for the three months ended September 30, 2013, was 39% oil, 30% NGLs and 31% gas, compared to 34% oil, 31% NGLs and 35% gas in the 2012 period. Production volumes increased during the three months ended September 30, 2013, as a result of our development project in the Permian Basin.

Commodity derivatives activities. Our commodity derivatives activity resulted in a realized loss of $840,000 for the three months ended September 30, 2013, compared to a realized gain of $423,000 for the three months ended September 30, 2012. Our average realized price, including the effect of commodity derivatives, was $53.38 per Boe for the three months ended September 30, 2013, compared to $44.78 per Boe for the three months ended September 30, 2012. Realized gains and losses on commodity derivatives are derived from the relative movement of commodity prices in relation to the fixed pricing in our derivatives contracts for the respective periods. The unrealized loss on commodity derivatives was $3.4 million and $4.2 million for the three months ended September 30, 2013 and 2012, respectively. As commodity prices increase, the fair value of the open portion of those positions decreases. As commodity prices decrease, the fair value of the open portion of those positions increases. Historically, we have not designated our derivatives instruments as cash-flow hedges. We record our open derivatives instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in net income on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

 

15


Lease operating. Our lease operating expenses (“LOE”) decreased $1.1 million, or 20%, to $4.4 million, or $5.38 per Boe, for the three months ended September 30, 2013, from $5.5 million, or $7.32 per Boe, for the three months ended September 30, 2012. The decrease in LOE per Boe for the three months ended September 30, 2013, was primarily due to a decrease in each of our four primary operating expense categories: well repairs, workovers and maintenance, compressor rental and repair, pumpers and supervision and water hauling and insurance. As our drilling activity increases in Project Pangea, we expect LOE per Boe could average between $5.00 per Boe and $7.00 per Boe for the full year. The following table summarizes LOE per Boe.

 

     Three Months Ended               
     September 30,               
     2013      2012      Change     % Change  

Water hauling, insurance and other

   $ 1.72       $ 1.80       $ (0.08     (4.4 )% 

Compressor rental and repair

     1.54         2.05         (0.51     (24.9

Well repairs, workovers and maintenance

     1.17         2.27         (1.10     (48.5

Pumpers and supervision

     0.95         1.20         (0.25     (20.8
  

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $ 5.38       $ 7.32       $ (1.94     (26.5 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Production and ad valorem taxes. Our production and ad valorem taxes increased $826,000, or 35%, for the three months ended September 30, 2013, to $3.2 million from $2.3 million for the three months ended September 30, 2012. The increase in production and ad valorem taxes was primarily a function of the increase in oil, NGL and gas sales between the two periods. Production and ad valorem taxes were $3.90 per Boe and approximately 7.2% of oil, NGL and gas sales for the three months ended September 30, 2013, compared to $3.13 per Boe and approximately 7.1% of oil, NGL and gas sales for the three months ended September 30, 2012.

Exploration. We recorded $1.2 million, or $1.47 per Boe, of exploration expense for the three months ended September 30, 2013, compared to $1.2 million, or $1.57 per Boe, for the three months ended September 30, 2012. Exploration expense for the three months ended September 30, 2013, resulted primarily from lease expirations.

General and administrative. Our general and administrative expenses (“G&A”) increased by $538,000, or 10%, to $6.2 million, or $7.60 per Boe, for the three months ended September 30, 2013, from $5.6 million, or $7.54 per Boe, for the three months ended September 30, 2012. The overall increase in G&A was primarily due to higher salaries and share-based compensation resulting from increased staffing, and other miscellaneous general and administrative expenses. The following table summarizes G&A (in millions) and G&A per Boe.

 

     Three Months Ended                      
     September 30,                      
     2013      2012      Change        
     $MM      Boe      $MM      Boe      $MM      Boe     % Change  

Salaries and benefits

   $ 2.5       $ 3.09       $ 2.4       $ 3.16       $ 0.1       $ (0.07     (2.2 )% 

Share-based compensation

     1.6         1.97         1.5         1.94         0.1         0.03        1.5   

Professional fees

     0.6         0.70         0.6         0.83                 (0.13     (15.7

Other

     1.5         1.84         1.1         1.61         0.4         0.23        14.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $ 6.2       $ 7.60       $ 5.6       $ 7.54       $ 0.6       $ 0.06        0.8
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expense (“DD&A”) increased $2.7 million, or 16%, to $19.4 million for the three months ended September 30, 2013, from $16.7 million for the three months ended September 30, 2012. Our DD&A per Boe increased by $1.52, or 7%, to $23.91 per Boe for the three months ended September 30, 2013, compared to $22.39 per Boe for the three months ended September 30, 2012. The increase in DD&A and DD&A per Boe over the prior year period was primarily due to higher production and oil and gas property carrying costs, relative to estimated proved developed reserves. The increase in oil and gas property carrying costs reflects the development of our oil-focused, Wolfcamp shale play.

 

16


Interest expense, net. Our interest expense, net, increased $3.6 million, or 235%, to $5.2 million for the three months ended September 30, 2013, from $1.5 million for the three months ended September 30, 2012. The increase in interest expense for the three months ended September 30, 2013, was primarily due to higher interest expense from the issuance of $250 million principal amount of 7% senior notes due 2021 (the “Senior Notes”) in June 2013. We expect our interest expense to remain higher than the prior year period as a result of our issuance of the Senior Notes.

Income taxes. Our income taxes increased $1.5 million to an income tax expense of $270,000 for the three months ended September 30, 2013, compared to an income tax benefit of $1.3 million for the three months ended September 30, 2012. Our effective income tax rate for the three months ended September 30, 2013, was 35.3%, compared to 34.7% for the three months ended September 30, 2012.

Nine Months Ended September 30, 2013, Compared to Nine Months Ended September 30, 2012

Oil, NGL and gas sales. Oil, NGL and gas sales increased $29.2 million, or 31%, to $122.7 million for the nine months ended September 30, 2013, from $93.6 million for the nine months ended September 30, 2012. The increase in oil, NGL and gas sales was due to an increase in production volumes ($26.7 million) and an increase in our average realized price ($2.5 million). Subject to commodity prices and future curtailments beyond our control, we expect our oil, NGL and gas sales to increase during the remainder of 2013 due to increased production volumes from our development project in the Permian Basin.

Net income. Net income for the nine months ended September 30, 2013, was $7.9 million, or $0.20 per diluted share, compared to net income of $7.2 million, or $0.21 per diluted share, for the nine months ended September 30, 2012. Net income for the nine months ended September 30, 2013, included an unrealized loss on commodity derivatives of $3.2 million and a realized loss on commodity derivatives of $1.2 million. Net income in the 2013 period increased due to higher revenues, partially offset by higher total expenses and losses on both our realized and unrealized commodity derivatives.

Oil, NGL and gas production. Production for the nine months ended September 30, 2013, totaled 2,383 MBoe (8.7 MBoe/d), compared to production of 2,103 MBoe (7.7 MBoe/d) in the prior year period, a 13% increase. Production for the nine months ended September 30, 2013, was 41% oil, 29% NGLs and 30% gas, compared to 32% oil, 32% NGLs and 36% gas in the 2012 period. Production volumes increased during the nine months ended September 30, 2013, as a result of our development project in the Permian Basin.

Commodity derivatives activities. Our commodity derivatives activity resulted in a realized loss of $1.2 million and a realized gain of $300,000 for the nine months ended September 30, 2013 and 2012, respectively. Our average realized price, including the effect of commodity derivatives, was $50.98 per Boe for the nine months ended September 30, 2013, compared to $44.63 per Boe for the nine months ended September 30, 2012. Realized gains and losses on commodity derivatives are derived from the relative movement of commodity prices in relation to the fixed pricing in our derivatives contracts for the respective periods. The unrealized loss on commodity derivatives was $3.2 million for the nine months ended September 30, 2013, compared to an unrealized gain of $2.6 million for the nine months ended September 30, 2012. As commodity prices increase, the fair value of the open portion of those positions decreases. As commodity prices decrease, the fair value of the open portion of those positions increases. Historically, we have not designated our derivatives instruments as cash-flow hedges. We record our open derivatives instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in net income on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

 

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Lease operating. Our LOE increased $460,000, or 3.5%, to $13.7 million, or $5.77 per Boe, for the nine months ended September 30, 2013, from $13.3 million, or $6.32 per Boe, for the nine months ended September 30, 2012. The decrease in LOE per BOE for the nine months ended September 30, 2013, was primarily due to a decrease in well repairs, workovers and maintenance, compressor rental and repair and pumpers and supervision, partially offset by an increase in water hauling and insurance. As our drilling activity increases in Project Pangea, we expect LOE per Boe could average between $5.00 per Boe and $7.00 per Boe for the full year. The following table summarizes LOE per Boe.

 

     Nine Months Ended               
     September 30,               
     2013      2012      Change     % Change  

Well repairs, workovers and maintenance

   $ 1.66       $ 1.71       $ (0.05     (2.9 )% 

Compressor rental and repair

     1.57         1.88         (0.31     (16.5

Water hauling, insurance and other

     1.54         1.51         0.03        2   

Pumpers and supervision

     1.00         1.22         (0.22     (18.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $ 5.77       $ 6.32       $ (0.55     (8.7 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Production and ad valorem taxes. Our production and ad valorem taxes increased $2 million, or 29%, for the nine months ended September 30, 2013, to $8.8 million from $6.8 million for the nine months ended September 30, 2012. The increase in production and ad valorem taxes was primarily a function of the increase in oil, NGL and gas sales between the two periods. Production and ad valorem taxes were $3.69 per Boe and approximately 7.2% of oil, NGL and gas sales for the nine months ended September 30, 2013, compared to $3.24 per Boe and approximately 7.3% of oil, NGL and gas sales for the nine months ended September 30, 2012.

Exploration. We recorded $2 million, or $0.84 per Boe, of exploration expense for the nine months ended September 30, 2013, compared to an exploration expense of $2.4 million, or $1.15 per Boe for the nine months ended September 30, 2012. Exploration expense for the nine months ended September 30, 2013, resulted primarily from the acquisition and processing of 3-D seismic data and lease expirations.

General and administrative. Our G&A increased $1.4 million, or 8%, to $17.8 million, or $7.47 per Boe, for the nine months ended September 30, 2013, from $16.4 million, or $7.82 per Boe, for the nine months ended September 30, 2012. The overall increase in G&A was primarily due to higher salaries and share-based compensation resulting from increased staffing, partially offset by a decrease in professional fees. The decrease in G&A per Boe was primarily attributable to an increase in production volumes over the prior year period. The following table summarizes G&A (in millions) and G&A per Boe.

 

     Nine Months Ended                     
     September 30,                     
     2013      2012      Change        
     $MM      Boe      $MM      Boe      $MM     Boe     % Change  

Salaries and benefits

   $ 7.1       $ 2.98       $ 6.5       $ 3.07       $ 0.6      $ (0.09     (2.9 )% 

Share-based compensation

     5.4         2.26         5.0         2.37         0.4        (0.11     (4.6

Professional fees

     1.1         0.44         1.5         0.70         (0.4     (0.26     (37.1

Other

     4.2         1.79         3.4         1.68         0.8        0.11        6.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total

   $ 17.8       $ 7.47       $ 16.4       $ 7.82       $ 1.4      $ (0.35     (4.5 )% 
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

 

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Depletion, depreciation and amortization. Our DD&A increased $12.6 million, or 30%, to $55 million for the nine months ended September 30, 2013, from $42.4 million for the nine months ended September 30, 2012. Our DD&A per Boe increased by $2.92, or 15%, to $23.06 per Boe for the nine months ended September 30, 2013, compared to $20.14 per Boe for the nine months ended September 30, 2012. The increase in DD&A and DD&A per Boe over the prior year period was primarily due to higher production and oil and gas property carrying costs, relative to estimated proved developed reserves. The increase in oil and gas property carrying costs reflects the development of our oil-focused, Wolfcamp shale play.

Interest expense, net. Our interest expense, net, increased $5 million, or 132.5%, to $8.9 million for the nine months ended September 30, 2013, from $3.8 million for the nine months ended September 30, 2012. The increase in interest expense for the nine months ended September 30, 2013, was primarily due to higher interest expense from the issuance of the Senior Notes in June 2013. We expect our interest expense to remain higher than the prior year period as a result of our issuance of the Senior Notes.

Income taxes. Our income taxes were $4.3 million and $4.1 million for the nine months ended September 30, 2013 and 2012, respectively. Our effective income tax rate for the nine months ended September 30, 2013, was 35.1%, compared to 36.3% for the nine months ended September 30, 2012.

Liquidity and Capital Resources

We generally will rely on cash generated from operations, available cash, borrowings under our Credit Facility and, to the extent that credit and capital market conditions will allow, future public equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our Credit Facility, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings beyond our Credit Facility will be available on acceptable terms, or at all, in the foreseeable future.

Our cash flows from operations are driven by commodity prices, production volumes, relative expense levels and the effect of commodity derivatives. Prices for oil, NGLs and gas are affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties.

We believe we have adequate liquidity from cash generated from operations, available cash from our issuance of the Senior Notes in June 2013 and unused borrowing capacity under our Credit Facility for current working capital needs and maintenance of our current development project. However, we may determine to use various financing sources, including the issuance of common stock, preferred stock, debt, convertible securities and other securities for future development of reserves, acquisitions, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all. Using some of these financing sources may require approval from the lenders under our Credit Facility.

 

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Liquidity

We define liquidity as funds available under our Credit Facility, cash and cash equivalents. At September 30, 2013, we had no borrowings outstanding under our Credit Facility, compared to $106 million in long-term debt outstanding under our Credit Facility at December 31, 2012. At September 30, 2013, and December 31, 2012, we had liquidity of $340.2 million and $174.4 million, respectively. The table below summarizes our liquidity position at September 30, 2013, and December 31, 2012 (dollars in thousands).

 

     Liquidity at
September 30,
    Liquidity at
December 31,
 
     2013     2012  

Borrowing base

   $ 315,000      $ 280,000   

Cash and cash equivalents

     25,489        767   

Long-term debt under Credit Facility

     —          (106,000

Undrawn letters of credit

     (325     (325
  

 

 

   

 

 

 

Liquidity

   $ 340,164      $ 174,442   
  

 

 

   

 

 

 

The lenders under our revolving credit facility completed their semi-annual borrowing base redetermination, resulting in an increase in the borrowing base to $350 million from $315 million effective November 6, 2013. In addition, we completed the sale of Wildcat in October 2013, and net proceeds to Approach at closing totaled approximately $109.1 million, after deducting our share of transactional costs paid at closing.

Working Capital

Our working capital is affected primarily by our cash and cash equivalents balance and our capital spending program. We had a working capital deficit of $62.6 million at September 30, 2013, compared to a working capital deficit of $44.6 million at December 31, 2012. The primary reason for the change in working capital was an increase in accrued liabilities and accounts payable from an increase in our capital expenditures. Historically we have maintained working capital deficits that have been more than offset by liquidity available under our Credit Facility. To the extent we operate or end the year 2013 with a working capital deficit, we expect such deficit to be more than offset by liquidity available under our Credit Facility.

Cash Flows

The following table summarizes our sources and uses of funds for the periods noted (in thousands).

 

     Nine Months Ended
September 30,
 
     2013     2012  

Cash flows provided by operating activities

   $ 118,996      $ 76,464   

Cash flows used in investing activities

     (230,187     (225,435

Cash flows provided by financing activities

     135,913        149,511   
  

 

 

   

 

 

 

Net increase in cash and cash equivalents

   $ 24,722      $ 540   
  

 

 

   

 

 

 

Operating Activities

Cash flows provided by operating activities increased by approximately $42.5 million during the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012, to $119 million. The increase in our cash flows provided by operating activities was primarily due to an increase in oil, NGL and gas sales and the timing of receipts and payments of working capital components, partially offset by an increase in total expenses. For the nine months ended September 30, 2013, our cash flows provided by operating activities and available cash were used primarily for drilling activities in Project Pangea.

 

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Investing Activities

Cash flows used in investing activities increased by approximately $4.8 million for the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012, to $230.2 million. Cash flows used in investing activities for the nine months ended September 30, 2013, were primarily attributable to drilling and development ($186.2 million), pipeline, infrastructure projects and other equipment ($26.3 million) and property and acreage acquisitions, lease extensions and 3-D seismic data processing ($9.4 million), all in Project Pangea. Additionally, cash flows used in investing activities during the nine months ended September 30, 2013, included $8.3 million in capital contributions to our joint venture for oil pipeline and facilities.

Financing Activities

Cash flows provided by financing activities decreased by $13.6 million, compared to the nine months ended September 30, 2012, to $135.9 million. During the nine months ended September 30, 2013, net cash flows provided by financing activities included borrowings under our Credit Facility ($129.1 million) and net proceeds from our offering of the Senior Notes ($242.7 million), which was partially offset by repayments of outstanding borrowings under our Credit Facility ($235.9 million). This compares to the nine months ended September 30, 2012, when we had net cash flows provided by financing activities that primarily included borrowings under our Credit Facility ($214 million) and proceeds from the issuance of common stock ($145 million) that were partially offset by repayments of outstanding borrowings ($210.3 million). In addition, during the nine months ended September 30, 2013 and 2012, we realized proceeds of $58,000 and $798,000, respectively, from the exercise of stock options.

Our current goal is to manage our borrowings to help us maintain financial flexibility and liquidity, and to avoid the problems associated with highly-leveraged companies with large interest costs and possible debt reductions restricting ongoing operations.

Credit Facility

Our Credit Facility has a maturity date of July 31, 2016. At September 30, 2013, our borrowing base was $315 million, with maximum commitments from the lenders in the Credit Facility of $500 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil, NGL and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year.

Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.75% to 1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment of 0.50% of unused borrowings available under our Credit Facility. Loans under our Credit Facility are secured by first priority liens on substantially all of our West Texas assets and are guaranteed by certain of our subsidiaries.

On November 6, 2013, we entered into a sixteenth amendment to the Credit Facility, which, among other things, increased the borrowing base to $350 million from $315 million.

 

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We had no outstanding borrowings under our Credit Facility at September 30, 2013, compared to outstanding borrowings of $106 million at December 31, 2012. The weighted average interest rate applicable to borrowings under our Credit Facility at December 31, 2012, was 2.7%. We also had outstanding unused letters of credit under our Credit Facility totaling $325,000 at September 30, 2013, which reduce amounts available for borrowing under our Credit Facility.

Covenants

Our Credit Facility contains two principal financial covenants:

 

    a consolidated modified current ratio covenant that requires us to maintain a ratio of not less than 1.0 to 1.0 at all times. The consolidated modified current ratio is calculated by dividing consolidated current assets (as defined in the Credit Facility) by consolidated current liabilities (as defined in the Credit Facility). As defined more specifically in the Credit Facility, the consolidated modified current ratio is calculated as current assets less current unrealized gains on commodity derivatives plus the available borrowing base at the respective balance sheet date, divided by current liabilities less current unrealized losses on commodity derivatives at the respective balance sheet date.

 

    a consolidated funded debt-to-consolidated EBITDAX ratio covenant that requires us to maintain a ratio of not more than 4.0 to 1.0 at the end of each fiscal quarter. The consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing consolidated funded debt (as defined in the Credit Facility) by consolidated EBITDAX (as defined in the Credit Facility). As defined more specifically in the Credit Facility, consolidated EBITDAX is calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, (6) income and franchise taxes and (7) certain other noncash expenses, less (1) gains or losses from sales or dispositions of assets, (2) unrealized gain on commodity derivatives and (3) extraordinary or nonrecurring gains. For purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the Credit Facility.

Our Credit Facility also restricts cash dividends and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investments in other entities and liens on properties.

In addition, our Credit Facility contains customary events of default that would permit our lenders to accelerate the debt under our Credit Facility if not cured within applicable grace periods, including, among others, failure to make payments of principal or interest when due, materially incorrect representations and warranties, failure to make mandatory prepayments in the event of borrowing base deficiencies, breach of covenants, defaults upon other obligations in excess of $500,000, events of bankruptcy, the occurrence of one or more unstayed judgments in excess of $500,000 not covered by an acceptable policy of insurance, failure to pay any obligation in excess of $500,000 owed under any derivatives transaction or in any amount if the obligation under the derivatives transaction is secured by collateral under the Credit Facility, any event of default by the Company occurs under any agreement entered into in connection with a derivatives transaction, liens securing the loans under the credit agreement cease to be in place, a change in control (as defined under the Credit Facility) of the Company occurs, and dissolution of the Company.

To date we have experienced no disruptions in our ability to access our Credit Facility. However, our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors, including the loan collateral value that each lender, in its discretion and using the methodology, assumptions and discount rates as such lender customarily uses in evaluating oil and gas properties, assigns to our properties.

 

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Senior Notes

In June 2013, we completed our public offering of $250 million principal amount of 7% Senior Notes due 2021. Interest on the Senior Notes is payable semi-annually on June 15 and December 15, beginning December 15, 2013. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under our Credit Facility. We will use the remaining net proceeds to fund our capital expenditures and for general working capital needs.

We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wells Fargo Bank, National Association, as trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.”

On and after June 15, 2016, we may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. Before June 15, 2016, we may redeem up to 35% of the Senior Notes at a redemption price of 107% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. In addition, before June 15, 2016, we may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the Senior Notes from holders. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries.

The Indenture restricts our ability, among other things, to (i) sell assets, (ii) pay distributions on, redeem or repurchase, equity interests, (iii) incur additional debt, (iv) make certain investments, (v) enter into transactions with affiliates, (v) incur liens and (vi) merge or consolidate with another company. These restrictions are subject to a number of important exceptions and qualifications. If at any time the Senior Notes are rated investment grade by both Moody’s Investors Service and Standard & Poor’s Ratings Services and no default (as defined in the Indenture) has occurred and is continuing, many of these restrictions will terminate. The Indenture contains customary events of default.

At September 30, 2013, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

Contractual Obligations

Our contractual obligations include long-term debt, daywork drilling contracts, operating lease obligations, asset retirement obligations and employment agreements with our executive officers. Since December 31, 2012, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our issuance of the Senior Notes in June 2013. In connection with the issuance of the Senior Notes, our annual interest expense related to the Senior Notes is $17.5 million due semi-annually on June 15 and December 15, beginning December 15, 2013. See “Liquidity and Capital Resources – Senior Notes” above for additional information on the Senior Notes.

 

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Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of September 30, 2013, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas delivery commitments. We do not believe that these arrangements have or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

General Trends and Outlook

Our financial results depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market demand, which is impacted by domestic and foreign supply of oil and gas, overall domestic and global economic conditions, commodity processing, gathering and transportation availability and the availability of refining capacity, price and availability of alternative fuels, price and quantity of foreign imports, domestic and foreign governmental regulations, political conditions in or affecting other gas producing and oil producing countries, weather and technological advances affecting oil and gas consumption. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. A substantial or extended decline in oil and gas prices could have a material adverse effect on our business, financial condition, results of operations, quantities of oil and gas reserves that may be economically produced and liquidity that may be accessed through our borrowing base under our Credit Facility and through capital markets.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success. Future finding and development costs are subject to changes in the industry, including the costs of acquiring, drilling and completing our projects. We focus our efforts on increasing oil and gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations will depend on our ability to manage our overall cost structure.

Like all oil and gas production companies, we face the challenge of natural production declines. Oil and gas production from a given well naturally decreases over time. Additionally, our reserves have a rapid initial decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves, farm-ins or other joint drilling ventures, and by acquisitions. However, during times of severe price declines, we may from time to time reduce current capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially reduce our production volumes and revenues and increase future expected costs necessary to develop existing reserves.

We also face the challenge of financing exploration, development and future acquisitions. We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our Credit Facility for current working capital needs and maintenance of our current development project. However, we may determine to use various financing sources, including the issuance of common stock, preferred stock, debt, convertible securities and other securities for future development of reserves, acquisitions, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all. Using some of these financing sources may require approval from the lenders under our Credit Facility.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking 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 gas prices, and other related factors. The disclosure is not meant to be a precise indicator

 

24


of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for commodity derivatives and investment purposes, not for trading purposes.

Commodity Price Risk

Given the current economic outlook, we expect commodity prices to remain volatile. Even modest decreases in commodity prices can materially affect our revenues and cash flow. In addition, if commodity prices remain suppressed for a significant amount of time, we could be required under successful efforts accounting rules to perform a write down of our oil and gas properties.

We enter into financial swaps, options and collars to reduce the risk of commodity price fluctuations. We do not designate such instruments as cash flow hedges. Accordingly, we record open commodity derivatives positions on our consolidated balance sheets at fair value and recognize changes in such fair values as other income (expense) on our consolidated statements of operations as they occur.

The table below summarizes our commodity derivatives positions outstanding at September 30, 2013.

 

Commodity and Period

   Contract
Type
   Volume Transacted    Contract Price

Crude Oil

        

2013

   Collar    650 Bbls/d    $90.00/Bbl – $105.80/Bbl

2013

   Collar    450 Bbls/d    $90.00/Bbl – $101.45/Bbl

2013 (1)

   Collar    1,200 Bbls/d    $90.35/Bbl – $100.35/Bbl

2014

   Collar    550 Bbls/d    $90.00/Bbl – $105.50/Bbl

2014

   Collar    950 Bbls/d    $85.05/Bbl – $95.05/Bbl

2015

   Collar    2,600 Bbls/d    $84.00/Bbl – $91.00/Bbl

Crude Oil Basis Differential (Midland/Cushing)

        

2013 (2)

   Swap    2,300 Bbls/d    $1.10/Bbl

2014

   Swap    1,500 Bbls/d    $0.55/Bbl

Natural Gas Liquids

        

Propane 2013 (3)

   Swap    550 Bbls/d    $42.00/Bbl

Propane 2014

   Swap    500 Bbls/d    $41.16/Bbl

Natural Gasoline 2013 (3)

   Swap    200 Bbls/d    $90.72/Bbl

Natural Gasoline 2014

   Swap    175 Bbls/d    $83.37/Bbl

Natural Gas

        

2013

   Swap    200,000 MMBtu/month    $3.54/MMBtu

2013

   Swap    190,000 MMBtu/month    $3.80/MMBtu

2013 (4)

   Collar    100,000 MMBtu/month    $4.00/MMBtu – $4.36/MMBtu

2014

   Swap    360,000 MMBtu/month    $4.18/MMBtu

 

(1) February 2013 – December 2013
(2) March 2013 – December 2013
(3) September 2013 – December 2013
(4) May 2013 – December 2013

Subsequent to September 30, 2013, we entered into a natural gas swap covering 200,000 MMBtu per month for 2015 at a contract price of $4.10/MMBtu.

 

25


At September 30, 2013, and December 31, 2012, the fair value of our open derivatives contracts was a net liability of $814,000 and a net asset of $2.4 million, respectively.

JPMorgan Chase Bank, N.A. and KeyBank National Association are currently the only counterparties to our commodity derivatives positions. We are exposed to credit losses in the event of nonperformance by counterparties on our commodity derivatives positions. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. JPMorgan is the administrative agent and a participant, and KeyBank is the documentation agent and a participant, in our Credit Facility and the collateral for the outstanding borrowings under our Credit Facility is used as collateral for our commodity derivatives.

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivatives contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

For the nine months ended September 30, 2013 and 2012, we recorded an unrealized loss on commodity derivatives of $3.2 million, compared to an unrealized gain of and $2.6 million, respectively, from the change in fair value of our commodity derivatives positions. A hypothetical 10% increase in commodity prices would have resulted in a $16.8 million decrease in the fair value of our commodity derivatives positions recorded on our balance sheet at September 30, 2013, and a corresponding increase in the unrealized loss on commodity derivatives recorded on our consolidated statement of operations for the nine months ended September 30, 2013.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Such controls include those designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including the President and Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

Our management, with the participation of our CEO and CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Exchange Act) as of September 30, 2013. Based on this evaluation, the CEO and CFO have concluded that, as of September 30, 2013, our disclosure controls and procedures were effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

 

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Internal Control over Financial Reporting

There were no changes made in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the three months ended September 30, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations Inherent in All Controls

Our management, including the CEO and CFO, recognizes that the disclosure controls and procedures and internal controls (discussed above) cannot prevent all errors or all attempts at fraud. Any controls system, no matter how well-crafted and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives. Because of the inherent limitations in any control system, no evaluation or implementation of a control system can provide complete assurance that all control issues and all possible instances of fraud have been or will be detected.

 

27


PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

There have been no material developments in the legal proceedings described in Part I, Item 3. “Legal Proceedings” of our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 28, 2013

Item 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the risks discussed in the following report that we have filed with the SEC, which risks could materially affect our business, financial condition and results of operations: Annual Report on Form 10-K for the year ended December 31, 2012, under the headings Item 1. “Business – Markets and Customers; Competition; and Regulation,” Item 1A. “Risk Factors,” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Trends and Outlook” and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” filed with the SEC on February 28, 2013; and Quarterly Report on Form 10-Q for the period ended June 30, 2013, under the heading item 1A. “Risk Factors” filed with the SEC on August 2, 2013.

There have been no material changes to the risk factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 28, 2013, and in our Quarterly Report on Form 10-Q for the period ended June 30, 2013, filed with the SEC on August 2, 2013, which are accessible on the SEC’s website at www.sec.gov and our website at www.approachresources.com.

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

The following table provides information relating to our purchase of shares of our common stock during the three months ended September 30, 2013. The repurchases reflect shares withheld upon vesting of restricted stock under our 2007 Stock Incentive Plan to satisfy statutory minimum tax withholding obligations.

ISSUER PURCHASES OF EQUITY SECURITIES

 

Period

   (a)
Total
Number of
Shares
Purchased
     (b)
Average
Price Paid
Per Share
     (c)
Total Number of
Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs
     (d)
Maximum
Number of Shares
that May Yet Be
Purchased Under
the Plans or
Programs
 

Month #1

July 1, 2013 – July 31, 2013

     —         $ —           —           —     

Month #2

August 1, 2013 – August 31, 2013

     577         26.11         —           —     

Month #3

September 1, 2013 – September 30, 2013

     1,255         24.33         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     1,832       $ 24.89         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

28


Item 6. Exhibits.

See “Index to Exhibits” following the signature page of this report for a description of the exhibits furnished as part of this report.

 

29


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.

 

    APPROACH RESOURCES INC.
Date: November 8, 2013     By:   /s/ J. Ross Craft
      J. Ross Craft
     

President and Chief Executive Officer

(Principal Executive Officer)

Date: November 8, 2013     By:   /s/ Steven P. Smart
      Steven P. Smart
     

Executive Vice President and Chief Financial Officer

(Principal Financial and Chief Accounting Officer)


Index to Exhibits

 

Exhibit
Number

  

Description of Exhibit

2.1    Equity Purchase Agreement by and among JP Energy Development LP, JP Energy Permian, LLC, Wildcat Midstream Mesquite, LLC, Approach Midstream Holdings LLC, Wildcat Permian Services LLC and joined in for certain limited purposes by Wildcat Midstream Holdings LLC, Approach Resources Inc. and Wildcat Midstream Operating, LLC dated September 18, 2013 (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission) (filed as Exhibit 2.1 of the Company’s Current Report on Form 8-K filed October 11, 2013, and incorporated herein by reference).
3.1    Restated Certificate of Incorporation of Approach Resources Inc. (filed as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed December 13, 2007, and incorporated herein by reference).
3.2    Second Amended and Restated Bylaws of Approach Resources Inc., effective November 6, 2013 (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed November 8, 2013, and incorporated herein by reference).
4.1    Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512), and incorporated herein by reference).
4.2    Senior Indenture, dated as of June 11, 2013, among Approach Resources Inc., as issuer, the subsidiary guarantors named therein, as guarantors, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed June 11, 2013, and incorporated herein by reference).
4.3    First Supplemental Indenture, dated as of June 11, 2013, among Approach Resources Inc., as issuer, the subsidiary guarantors named therein, as guarantors, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed June 11, 2013, and incorporated herein by reference).
*31.1    Certification by the President and Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2    Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1    Certification by the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2    Certification by the Chief Financial Officer Pursuant to U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS    XBRL Instance Document.
*101.SCH    XBRL Taxonomy Extension Schema Document.
*101.CAL    XBRL Taxonomy Extension Calculation Linkbase Document.
*101.LAB    XBRL Taxonomy Extension Label Linkbase Document.
*101.PRE    XBRL Taxonomy Extension Presentation Linkbase Document.
*101.DEF    XBRL Taxonomy Extension Definition Linkbase Document.

 

* Filed herewith.