UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended
September 30, 2012
Commission file number: 001-34635
POSTROCK ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
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27-0981065
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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210 Park Avenue, Oklahoma City, OK 73102
(Address of principal executive offices) (Zip Code)
(405) 600-7704
(Registrant’s telephone number, including area code)
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 past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90
days. Yes
x
No
¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files). Yes
x
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. (Check one):
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Large accelerated filer
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¨
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Accelerated filer
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¨
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Non-accelerated filer
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¨
(Do not check if a smaller reporting company)
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Smaller reporting company
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x
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes
¨
No
x
At November 5, 2012, there were 15,566,796 outstanding shares of the registrant’s common stock having an aggregate market value
of $22.6 million based on a closing price of $1.45 per share.
POSTROCK ENERGY CORPORATION
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2012
TABLE OF CONTENTS
i
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
POSTROCK ENERGY CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
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December 31,
2011
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September 30,
2012
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(Unaudited)
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ASSETS
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Current assets
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Cash and equivalents
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$
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349
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$
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162
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Accounts receivable—trade, net
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7,785
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5,474
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Other receivables
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1,164
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212
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Inventory
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1,681
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1,374
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Other
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7,455
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3,713
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Derivative financial instruments
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42,803
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34,484
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Assets of discontinued operations
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1,585
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—
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Total
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62,822
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45,419
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Oil and natural gas properties, full cost method of accounting, net
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124,068
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110,774
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Other property and equipment, net
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14,465
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14,900
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Other, net
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2,812
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512
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Equity investment
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12,994
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8,416
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Derivative financial instruments
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29,516
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8,585
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Assets of discontinued operations
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60,034
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—
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Total assets
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$
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306,711
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$
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188,606
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LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
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Current liabilities
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Accounts payable
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$
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5,723
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$
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2,717
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Revenue payable
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4,972
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3,915
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Accrued expenses and other
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8,327
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7,883
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Litigation reserve
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3,081
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4,484
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Current portion of long-term debt
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3,000
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102,855
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Derivative financial instruments
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5,223
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4,440
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Liabilities of discontinued operations
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936
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—
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Total
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31,262
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126,294
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Derivative financial instruments
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4,611
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1,980
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Long term debt
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190,000
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—
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Asset retirement obligations
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10,087
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10,665
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Other
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4,559
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301
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Liabilities of discontinued operations
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1,646
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—
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Total liabilities
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242,165
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139,240
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Commitments and contingencies
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Series A Cumulative Redeemable Preferred Stock, $0.01 par value; 6,000 and 6,600 shares issued and outstanding,
respectively
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56,736
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66,613
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Stockholders’ equity
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Preferred stock, $0.01 par value; 5,000,000 authorized shares; 215,662 and 249,215 Series B Voting Preferred Stock
issued and outstanding, respectively
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2
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2
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Common stock, $0.01 par value; 100,000,000 authorized shares; 9,935,337 and 15,562,177 issued and outstanding,
respectively
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99
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156
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Additional paid-in capital
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378,093
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389,314
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Accumulated deficit
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(370,384
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)
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(406,719
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)
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Total equity (deficit)
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7,810
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(17,247
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)
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Total liabilities and equity (deficit)
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$
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306,711
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$
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188,606
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The accompanying notes are an integral part of these statements.
F-1
POSTROCK ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)
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Three Months Ended
September
30,
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Nine
months Ended
September 30,
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2011
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2012
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2011
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2012
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Revenues
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Natural gas sales
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$
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18,889
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$
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10,819
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$
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57,052
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$
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31,069
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Crude oil sales
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1,654
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2,232
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5,253
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6,254
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Gathering
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1,383
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646
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4,272
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1,819
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Total
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21,926
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13,697
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66,577
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39,142
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Costs and expenses
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Production expense
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11,845
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9,917
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35,685
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32,117
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General and administrative
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3,952
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3,495
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13,401
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11,329
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Litigation reserve
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1,981
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—
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11,581
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—
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Depreciation, depletion and amortization
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5,874
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7,321
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17,780
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20,423
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Impairment of oil and gas properties
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—
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4,309
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—
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4,309
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Loss (gain) on disposal of assets
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(32
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)
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64
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(12,386
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)
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226
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Total
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23,620
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25,106
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66,061
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68,404
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Operating income (loss)
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(1,694
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)
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(11,409
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)
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516
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(29,262
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)
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Other income (expense)
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Realized gain from derivative financial instruments
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7,264
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2,666
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23,171
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33,369
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Unrealized gain (loss) from derivative financial instruments
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4,689
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(6,523
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)
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(6,471
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)
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(25,360
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)
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Loss from equity investment
|
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(859
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)
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(2,111
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)
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(859
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)
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(4,578
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)
|
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Gain on forgiveness of debt
|
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—
|
|
|
|
—
|
|
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|
1,647
|
|
|
|
255
|
|
|
Other income, net
|
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|
23
|
|
|
|
62
|
|
|
|
193
|
|
|
|
80
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|
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Interest expense, net
|
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|
(2,485
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)
|
|
|
(2,615
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)
|
|
|
(7,474
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)
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|
|
(7,835
|
)
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|
|
|
|
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|
|
|
|
|
|
|
|
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|
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Total other income (expense)
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8,632
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|
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|
(8,521
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)
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10,207
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|
(4,069
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)
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|
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|
|
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|
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Income (loss) from continuing operations before income taxes
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6,938
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|
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|
(19,930
|
)
|
|
|
10,723
|
|
|
|
(33,331
|
)
|
|
Income taxes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Net income (loss) from continuing operations
|
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|
6,938
|
|
|
|
(19,930
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)
|
|
|
10,723
|
|
|
|
(33,331
|
)
|
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Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
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Income (loss) from discontinued operations
|
|
|
69
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|
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|
(5,244
|
)
|
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(46
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)
|
|
|
(3,004
|
)
|
|
Income taxes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
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|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Net income (loss) from discontinued operations
|
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|
69
|
|
|
|
(5,244
|
)
|
|
|
(46
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)
|
|
|
(3,004
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
7,007
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|
|
|
(25,174
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)
|
|
|
10,677
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|
|
|
(36,335
|
)
|
|
Preferred stock dividends
|
|
|
(1,973
|
)
|
|
|
(2,341
|
)
|
|
|
(5,747
|
)
|
|
|
(6,589
|
)
|
|
Accretion of redeemable preferred stock
|
|
|
(406
|
)
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|
|
(568
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)
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(1,141
|
)
|
|
|
(1,540
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)
|
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
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|
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Net income (loss) available to common stock
|
|
$
|
4,628
|
|
|
$
|
(28,083
|
)
|
|
$
|
3,789
|
|
|
$
|
(44,464
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share available to common stock
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Basic income (loss) per share—continuing operations
|
|
$
|
0.51
|
|
|
$
|
(1.58
|
)
|
|
$
|
0.45
|
|
|
$
|
(3.26
|
)
|
|
Basic income (loss) per share—discontinued operations
|
|
$
|
—
|
|
|
$
|
(0.36
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic income (loss) per share
|
|
$
|
0.51
|
|
|
$
|
(1.94
|
)
|
|
$
|
0.44
|
|
|
$
|
(3.50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income (loss) per share—continuing operations
|
|
$
|
0.28
|
|
|
$
|
(1.58
|
)
|
|
$
|
0.23
|
|
|
$
|
(3.26
|
)
|
|
Diluted income (loss) per share—discontinued operations
|
|
$
|
0.01
|
|
|
$
|
(0.36
|
)
|
|
$
|
—
|
|
|
$
|
(0.24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income (loss) per share
|
|
$
|
0.29
|
|
|
$
|
(1.94
|
)
|
|
$
|
0.23
|
|
|
$
|
(3.50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
9,009
|
|
|
|
14,477
|
|
|
|
8,528
|
|
|
|
12,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
16,009
|
|
|
|
14,477
|
|
|
|
16,753
|
|
|
|
12,702
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these statements.
F-2
POSTROCK ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
September 30,
|
|
|
|
|
2011
|
|
|
2012
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
10,677
|
|
|
$
|
(36,335
|
)
|
|
Adjustments to reconcile net income (loss) to net cash provided by operations
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
20,482
|
|
|
|
22,960
|
|
|
Impairment of oil and gas properties
|
|
|
—
|
|
|
|
4,309
|
|
|
Stock-based compensation
|
|
|
1,184
|
|
|
|
1,554
|
|
|
Amortization of deferred loan costs
|
|
|
1,278
|
|
|
|
1,208
|
|
|
Change in fair value of derivative financial instruments
|
|
|
6,471
|
|
|
|
25,836
|
|
|
Litigation reserve
|
|
|
6,031
|
|
|
|
—
|
|
|
Loss (gain) on disposal of assets
|
|
|
(12,385
|
)
|
|
|
5,811
|
|
|
Gain on forgiveness of debt
|
|
|
(1,647
|
)
|
|
|
(255
|
)
|
|
Loss from equity investment
|
|
|
859
|
|
|
|
4,578
|
|
|
Other non-cash changes to net income
|
|
|
562
|
|
|
|
389
|
|
|
Change in assets and liabilities
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
1,494
|
|
|
|
3,253
|
|
|
Payables
|
|
|
(2,806
|
)
|
|
|
(8,803
|
)
|
|
Other
|
|
|
(2,725
|
)
|
|
|
4,927
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows from operating activities
|
|
|
29,475
|
|
|
|
29,432
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
28
|
|
|
|
—
|
|
|
Proceeds from sale of equity securities
|
|
|
1,634
|
|
|
|
—
|
|
|
Equity investment
|
|
|
(6,864
|
)
|
|
|
—
|
|
|
Proceeds from sale of assets
|
|
|
10,706
|
|
|
|
53,201
|
|
|
Equipment, development, leasehold and pipeline
|
|
|
(23,398
|
)
|
|
|
(12,276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows from (used in) investing activities
|
|
|
(17,894
|
)
|
|
|
40,925
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock
|
|
|
—
|
|
|
|
13,682
|
|
|
Proceeds from issuance of preferred stock and warrants
|
|
|
—
|
|
|
|
6,000
|
|
|
Proceeds from debt
|
|
|
3,000
|
|
|
|
—
|
|
|
Repayments of debt
|
|
|
(15,319
|
)
|
|
|
(90,145
|
)
|
|
Proceeds from stock option exercise
|
|
|
66
|
|
|
|
—
|
|
|
Equity issuance costs
|
|
|
—
|
|
|
|
(81
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows used in financing activities
|
|
|
(12,253
|
)
|
|
|
(70,544
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash
|
|
|
(672
|
)
|
|
|
(187
|
)
|
|
Cash and equivalents—beginning of period
|
|
|
730
|
|
|
|
349
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and equivalents—end of period
|
|
$
|
58
|
|
|
$
|
162
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these statements.
F-3
POSTROCK ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Amounts subsequent to December 31, 2011 are unaudited)
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
Shares
|
|
|
Preferred
Stock
|
|
|
Common
Shares
Issued
|
|
|
Common
Stock
|
|
|
Additional
Paid-in
Capital
|
|
|
Accumulated
Deficit
|
|
|
Total
Equity
|
|
|
Balance, December 31, 2011
|
|
|
215,662
|
|
|
$
|
2
|
|
|
|
9,935,337
|
|
|
$
|
99
|
|
|
$
|
378,093
|
|
|
$
|
(370,384
|
)
|
|
$
|
7,810
|
|
|
Stock-based compensation
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,554
|
|
|
|
—
|
|
|
|
1,554
|
|
|
Restricted stock grants, net of forfeitures
|
|
|
—
|
|
|
|
—
|
|
|
|
284,657
|
|
|
|
3
|
|
|
|
(3
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Issuance of Series B preferred stock
|
|
|
33,553
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Issuance of warrants
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
4,252
|
|
|
|
—
|
|
|
|
4,252
|
|
|
Issuance of common stock
|
|
|
—
|
|
|
|
—
|
|
|
|
5,342,183
|
|
|
|
54
|
|
|
|
13,547
|
|
|
|
—
|
|
|
|
13,601
|
|
|
Preferred stock dividends
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(6,589
|
)
|
|
|
—
|
|
|
|
(6,589
|
)
|
|
Preferred stock accretion
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(1,540
|
)
|
|
|
—
|
|
|
|
(1,540
|
)
|
|
Net loss
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(36,335
|
)
|
|
|
(36,335
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2012
|
|
|
249,215
|
|
|
$
|
2
|
|
|
|
15,562,177
|
|
|
$
|
156
|
|
|
$
|
389,314
|
|
|
$
|
(406,719
|
)
|
|
$
|
(17,247
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these statements.
F-4
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Basis of Presentation
PostRock Energy Corporation is an
independent oil and gas company operating under one segment that includes the acquisition, exploration, development, production and gathering of crude oil and natural gas. Its primary production activity is focused in the Cherokee Basin, a 15-county
region in southeastern Kansas and northeastern Oklahoma. It also has minor oil producing properties in Oklahoma and oil and gas producing properties in the Appalachian Basin. The Company previously owned a 1,120 mile interstate natural gas
pipeline, which transported natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City. The pipeline was sold in September 2012. Unless the context requires otherwise, references to “PostRock,” the
“Company,” “we,” “us” and “our” refer to PostRock Energy Corporation and its consolidated subsidiaries.
The unaudited interim condensed consolidated financial statements have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and
reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a
normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America
(“GAAP”) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These condensed consolidated financial statements should
be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011
10-K”).
The preparation of condensed consolidated financial statements in conformity with GAAP requires management to
make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those estimates. The operating results for the interim periods are not necessarily indicative of the results to be expected for the full year.
Certain reclassifications have been made to amounts reported in the previous periods to conform to the current presentation. Among other
items, revenues and expenses directly related to the Company’s interstate pipeline sold in September 2012 have been reclassified from continuing operations to discontinued operations for all periods presented. In addition, the assets and
liabilities of the interstate pipeline have been separately reflected in the accompanying condensed consolidated balance sheet for the prior period as assets and liabilities of discontinued operations. The separate presentation in the prior period
balance sheet is intended to enhance comparability of the assets and liabilities held and used.
Recently Adopted Accounting
Pronouncements
In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting
Standards Update (“ASU”) 2010-06,
Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.
The update requires reporting entities to provide information about movements of assets
among Levels 1 and 2 of the three-tier fair value hierarchy established under FASB ASC 820. The update also requires separate presentation (on a gross basis rather than as one net number) about purchases, sales, issuances, and settlements within the
reconciliation of activity in Level 3 fair value measurements. The guidance is effective for any fiscal period beginning after December 15, 2009, except for the requirement to separately disclose purchases, sales, issuances, and settlements,
which is effective for any fiscal period beginning after December 15, 2010. The Company adopted the provisions of this update relating to disclosure on movement of assets among Levels 1 and 2 beginning with the quarter ended March 31,
2010, while the provisions requiring gross presentation of activity within Level 3 assets were adopted beginning with the quarter ended March 31, 2011. The adoption did not have a material impact on the Company’s consolidated financial
statements.
In May 2011, the FASB issued ASU 2011-04
Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair
Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs
. ASU 2011-04 clarifies the principles and definitions used to measure fair value and expands disclosure requirements in order to achieve
F-5
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
greater consistency between U.S. GAAP and International Financial Reporting Standards. The amendment does not require additional fair value measurements and is not intended to establish valuation
standards or affect valuation practices outside of financial reporting. ASU 2011-04 is to be applied prospectively and is effective during interim and annual periods beginning after December 15, 2011. The adoption did not have a material impact
on the Company’s consolidated financial statements.
In June 2011, the FASB issued ASU 2011-
05 Comprehensive Income
(Topic 220): Presentation of Comprehensive Income
. ASU 2011-05 requires that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive
statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other
comprehensive income and the total of comprehensive income. Certain provisions in this update relating to the new presentation for reclassifications of items out of accumulated other comprehensive income have been delayed indefinitely. The remaining
amendments are to be applied retrospectively and are effective for fiscal years and interim periods within those years beginning after December 15, 2011. The adoption did not have any impact on the Company’s consolidated financial
statements.
Note 2 — Divestitures
Appalachian Basin Sale —
In December 2010, the Company entered into an agreement with Magnum Hunter Resources Corporation (“MHR”) to sell certain oil and gas properties and related
assets in West Virginia. The sale closed in three phases in December 2010, January 2011 and June 2011 for a total of $44.6 million. The amount received for the first and second phases was paid half in cash and half in MHR common stock, while
the amount received for the third phase was paid entirely in cash. Gains of $9.9 million and $2.5 million, net of $225,000 and $2.4 million in selling costs and adjustments, were recorded in January 2011 and June 2011 related to the second and third
phases of the sale. The corresponding reduction in the Company’s oil and gas full cost pool was $1.5 million for the second closing, with no reduction for the third closing.
Of the total proceeds received from all three phases of the sale, $6.4 million was set aside in escrow to cover potential claims for
indemnity and title defects. In June 2012, $5.7 million of escrowed funds relating to the first and second closing was released after net claims of $219,000 were paid. Of the $5.7 million released to the Company, $1.3 million was retained by the
Company while $4.4 million was paid to Royal Bank of Canada (“RBC”) under the previously disclosed asset sale agreement with RBC. The $219,000 of net claims paid out of escrow effectively reduced the net proceeds received on the sale, and
along with certain post-closing adjustments, resulted in a $266,000 reduction in the gain on sale recognized in June 2012. At September 30, 2012, the remaining balance in escrow was $564,000. The balance is related to the third closing and,
subject to certain contingencies, is scheduled to be released in December 2012. The escrow balance is reflected in the condensed consolidated balance sheet as a component of other current assets. If the entire remaining amount in escrow is released,
the Company would retain $164,000 while $400,000 will be paid to a third-party. The amount payable to the third party is reflected in the condensed consolidated balance sheet in “accrued expenses and other.”
KPC Sale
— On September 28, 2012, the Company consummated the sale of its interstate pipeline subsidiary PostRock KPC
Pipeline, LLC ( “KPC”) to MV Pipelines, LLC (“MV”) for a gross purchase price to be paid at closing of $53.5 million. After adjustment for working capital, the Company received $52.9 million in cash at closing, and an additional
$500,000 was deposited in escrow to be released to the Company upon acceptable cleanup of a site previously owned by KPC. Details of the transaction are discussed further in Note 13 — Discontinued Operations.
F-6
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Note 3 — Other Balance Sheet Items
The following describes the components of the following condensed consolidated balance sheet items (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2011
|
|
|
September 30,
2012
|
|
|
Other current assets
|
|
|
|
|
|
|
|
|
|
Prepaid fees and deposits
|
|
$
|
985
|
|
|
$
|
1,419
|
|
|
Escrowed funds from Appalachian Basin sale (1)
|
|
|
6,439
|
|
|
|
564
|
|
|
Escrowed funds from KPC sale (2)
|
|
|
—
|
|
|
|
500
|
|
|
Deferred financing costs
|
|
|
31
|
|
|
|
1,219
|
|
|
Other
|
|
|
—
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,455
|
|
|
$
|
3,713
|
|
|
|
|
|
|
|
|
|
|
|
|
Other noncurrent assets, net
|
|
|
|
|
|
|
|
|
|
Deferred financing costs
|
|
$
|
2,270
|
|
|
$
|
—
|
|
|
Noncurrent deposits and other
|
|
|
542
|
|
|
|
512
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,812
|
|
|
$
|
512
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued expenses and other
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
53
|
|
|
$
|
37
|
|
|
Employee-related costs and benefits
|
|
|
1,294
|
|
|
|
2,483
|
|
|
Non-income related taxes
|
|
|
41
|
|
|
|
1,937
|
|
|
Escrowed funds due to third parties (3)
|
|
|
4,981
|
|
|
|
400
|
|
|
Fees for services
|
|
|
1,042
|
|
|
|
1,587
|
|
|
Other
|
|
|
916
|
|
|
|
1,439
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8,327
|
|
|
$
|
7,883
|
|
|
|
|
|
|
|
|
|
|
|
|
Other noncurrent liabilities
|
|
|
|
|
|
|
|
|
|
Litigation reserve (4)
|
|
$
|
4,111
|
|
|
$
|
—
|
|
|
Lease termination costs
|
|
|
440
|
|
|
|
301
|
|
|
Other
|
|
|
8
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,559
|
|
|
$
|
301
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Escrowed funds relate to the proceeds from the Appalachian Basin sale. The escrowed funds are restricted to cover indemnities and title defects related to the sale. In
June 2012, $5.7 million in escrowed funds were released after $219,000 in net claims were paid. The remaining $564,000 is scheduled to be released in December 2012. If the entire remaining amount in escrow is released, the Company would retain
$164,000 while $400,000 would be paid to a third party.
|
|
(2)
|
Escrowed funds relate to the proceeds from the KPC sale and will be released to the Company upon acceptable cleanup of a site previously owned by KPC.
|
|
(3)
|
The balance at December 31, 2011, represents the portion of escrowed funds from the Appalachian Basin sale that, upon release, would be payable to RBC and a third
party. In June 2012, $4.4 million was paid to RBC and net claims of $219,000 were paid. The balance at September 30, 2012, is payable to a third party.
|
|
(4)
|
Recorded at present value. At September 30, 2012, litigation reserve is presented as a separate item within current liabilities.
|
Note 4 — Derivative Financial Instruments
The Company is exposed to commodity price risk and management believes it prudent to periodically reduce exposure to cash-flow variability resulting from this volatility. Accordingly, the Company enters
into certain derivative financial instruments in order to manage exposure to commodity price risk inherent in its oil and gas production. Derivative financial instruments are also used to manage commodity price risk inherent in customer pricing
requirements and to fix margins on the future sale of natural gas. Specifically, the Company may utilize futures, swaps and options.
F-7
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Derivative instruments expose the Company to counterparty credit risk. The
Company’s commodity derivative instruments are currently with several counterparties. The Company generally executes commodity derivative instruments under master agreements which allow it, in the event of default, to elect early termination of
all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election.
The Company monitors the creditworthiness of its counterparties; however, it is not able to predict sudden changes in
counterparties’ creditworthiness. In addition, even if such changes are not sudden, it may be limited in its ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer its position to another counterparty
or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices
as well as incur a loss. The Company includes a measure of counterparty credit risk in its estimates of the fair values of derivative instruments in an asset position.
The Company does not designate its derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, it recognizes the change in the respective instruments’
fair value currently in earnings. The table below outlines the classification of derivative financial instruments on the condensed consolidated balance sheet and their financial impact on the condensed consolidated statements of operations at and
for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments
|
|
Balance Sheet location
|
|
December 31,
2011
|
|
|
September 30,
2012
|
|
|
Commodity contracts
|
|
Current derivative financial instrument asset
|
|
$
|
42,803
|
|
|
$
|
34,484
|
|
|
Commodity contracts
|
|
Long-term derivative financial instrument asset
|
|
|
29,516
|
|
|
|
8,585
|
|
|
Commodity contracts
|
|
Current derivative financial instrument liability
|
|
|
(5,223
|
)
|
|
|
(4,440
|
)
|
|
Commodity contracts
|
|
Long-term derivative financial instrument liability
|
|
|
(4,611
|
)
|
|
|
(1,980
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
62,485
|
|
|
$
|
36,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains and losses associated with derivative financial instruments related to oil and gas production were
as follows for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
September 30,
|
|
|
Nine
Months Ended
September 30,
|
|
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
Realized gains (losses)
|
|
$
|
7,264
|
|
|
$
|
2,666
|
|
|
$
|
23,171
|
|
|
$
|
33,369
|
|
|
Unrealized gains (losses)
|
|
|
4,689
|
|
|
|
(6,523
|
)
|
|
|
(6,471
|
)
|
|
|
(25,360
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
11,953
|
|
|
$
|
(3,857
|
)
|
|
$
|
16,700
|
|
|
$
|
8,009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-8
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table summarizes the estimated volumes, fixed prices and fair values
attributable to all of the Company’s oil and gas derivative contracts at September 30, 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remainder
of
2012
|
|
|
Year Ending December 31,
|
|
|
Total
|
|
|
|
|
|
2013
|
|
|
2014
|
|
|
2015-2016
|
|
|
|
|
|
($ in thousands, except per unit data)
|
|
|
Natural Gas Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
2,762,296
|
|
|
|
9,000,003
|
|
|
|
—
|
|
|
|
1,047,000
|
|
|
|
12,809,299
|
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
7.21
|
|
|
$
|
7.28
|
|
|
$
|
—
|
|
|
$
|
4.00
|
|
|
$
|
7.00
|
|
|
Fair value, net
|
|
$
|
10,868
|
|
|
$
|
30,849
|
|
|
$
|
—
|
|
|
$
|
(710
|
)
|
|
$
|
41,007
|
|
|
Natural Gas Basis Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
2,262,295
|
|
|
|
9,000,003
|
|
|
|
—
|
|
|
|
—
|
|
|
|
11,262,298
|
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
(0.71
|
)
|
|
$
|
(0.71
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.71
|
)
|
|
Fair value, net
|
|
$
|
(1,097
|
)
|
|
$
|
(4,563
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(5,660
|
)
|
|
Crude Oil Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Bbl)
|
|
|
16,671
|
|
|
|
65,892
|
|
|
|
61,680
|
|
|
|
112,056
|
|
|
|
256,299
|
|
|
Weighted-average fixed price per Bbl
|
|
$
|
93.86
|
|
|
$
|
101.70
|
|
|
$
|
97.00
|
|
|
$
|
92.29
|
|
|
$
|
95.95
|
|
|
Fair value, net
|
|
$
|
19
|
|
|
$
|
525
|
|
|
$
|
335
|
|
|
$
|
423
|
|
|
$
|
1,302
|
|
|
Total fair value, net
|
|
$
|
9,790
|
|
|
$
|
26,811
|
|
|
$
|
335
|
|
|
$
|
(287
|
)
|
|
$
|
36,649
|
|
In April 2012, the Company repriced the portion of its natural gas swap contracts expected to settle in
June, July and August of 2012 to market prices and received proceeds of $10.8 million. In May 2012, the Company settled the repriced June 2012 contract by entering into new contracts to be settled in 2016. The settlement transaction resulted in
a realized loss on derivative instruments of $476,000.
The following table summarizes the estimated volumes, fixed prices and
fair values attributable to all of the Company’s oil and gas derivative contracts at December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
|
2012
|
|
|
2013
|
|
|
Total
|
|
|
|
|
($ in thousands, except per unit data)
|
|
|
Natural Gas Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
11,000,004
|
|
|
|
9,000,003
|
|
|
|
20,000,007
|
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
7.13
|
|
|
$
|
7.28
|
|
|
$
|
7.20
|
|
|
Fair value, net
|
|
$
|
42,803
|
|
|
$
|
29,516
|
|
|
$
|
72,319
|
|
|
Natural Gas Basis Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
9,000,000
|
|
|
|
9,000,003
|
|
|
|
18,000,003
|
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
(0.70
|
)
|
|
$
|
(0.71
|
)
|
|
$
|
(0.71
|
)
|
|
Fair value, net
|
|
$
|
(4,767
|
)
|
|
$
|
(4,611
|
)
|
|
$
|
(9,378
|
)
|
|
Crude Oil Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Bbl)
|
|
|
42,000
|
|
|
|
—
|
|
|
|
42,000
|
|
|
Weighted-average fixed price per Bbl
|
|
$
|
87.90
|
|
|
$
|
—
|
|
|
$
|
87.90
|
|
|
Fair value, net
|
|
$
|
(456
|
)
|
|
$
|
—
|
|
|
$
|
(456
|
)
|
|
Total fair value, net
|
|
$
|
37,580
|
|
|
$
|
24,905
|
|
|
$
|
62,485
|
|
F-9
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Note 5 — Fair Value Measurements
Certain assets and liabilities are measured at fair value on a recurring basis in the Company’s condensed consolidated balance
sheets. The following methods and assumptions were used to estimate the fair values:
Cash and Equivalents, Accounts
Receivable and Accounts Payable
The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
Commodity Derivative Instruments
The Company’s oil and gas derivative instruments may consist of variable to fixed price swaps, collars and basis swaps. When possible, the Company estimates
the fair values of these instruments based on published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates adjusted for counterparty credit
risk. Counterparty credit risk is incorporated into derivative assets while the Company’s own credit risk is incorporated into derivative liabilities. Both are based on the current published credit default swap rates.
Equity Investment
The Company owns an equity investment in Constellation Energy Partners LLC (“CEP”). At
September 30, 2012, the investment included 483,304 Class A Member Interests and 5,918,894 Class B Member Interests, for a total 26.5% voting interest in CEP. Fair value for the Class B Member Interests, which are publicly traded, is based
on market price and classified as a Level 1 measurement under the fair value hierarchy. Fair value for the Class A Member Interests, classified as a Level 2 measurement, is based on the market price of the publicly traded interests and a
premium reflecting certain additional rights. At September 30, 2012, the fair values used for the Class A units and the Class B units were $1.86 and $1.27 per unit, respectively.
Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total Net
Fair
Value
|
|
|
At December 31, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity investment
|
|
$
|
11,601
|
|
|
$
|
1,393
|
|
|
$
|
—
|
|
|
$
|
12,994
|
|
|
Derivative financial instruments—assets
|
|
|
—
|
|
|
|
72,319
|
|
|
|
—
|
|
|
|
72,319
|
|
|
Derivative financial instruments—liabilities
|
|
|
—
|
|
|
|
(9,834
|
)
|
|
|
—
|
|
|
|
(9,834
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
11,601
|
|
|
$
|
63,878
|
|
|
$
|
—
|
|
|
$
|
75,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At September 30, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity investment
|
|
$
|
7,517
|
|
|
$
|
899
|
|
|
$
|
—
|
|
|
$
|
8,416
|
|
|
Derivative financial instruments—assets
|
|
|
—
|
|
|
|
43,069
|
|
|
|
—
|
|
|
|
43,069
|
|
|
Derivative financial instruments—liabilities
|
|
|
—
|
|
|
|
(6,420
|
)
|
|
|
—
|
|
|
|
(6,420
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,517
|
|
|
$
|
37,548
|
|
|
$
|
—
|
|
|
$
|
45,065
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company classifies assets and liabilities within the fair value hierarchy based on the lowest level
of input that is significant to the fair value measurement of each individual asset and liability taken as a whole.
There
were no movements between Levels 1 and 2 during the nine months ended September 30, 2012. In June 2011, the Company transferred 23,517 shares of MHR common stock with a fair value of $159,000 from Level 2 to Level 1 due to the limited amount of
time remaining until restrictions on the Company’s ability to trade these securities lapsed in July 2011. The lifting of restrictions enabled the Company to value these securities at published market prices. These securities were subsequently
sold in July 2011.
The following table sets forth a reconciliation of changes in the fair value of risk management assets and
liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2011 (in thousands). With respect to Level 3 assets or liabilities, there were no transfers, purchases, sales or issuances during this time
period. The Company did not own any Level 3 assets and liabilities during the nine month period ended September 30, 2012.
F-10
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
|
|
|
|
|
|
|
|
|
Nine Months
Ended
September 30, 2011
|
|
|
Balance at beginning of period
|
|
$
|
(9,853
|
)
|
|
Realized and unrealized gains included in earnings
|
|
|
(2,025
|
)
|
|
Transfers out of Level 3 (1)
|
|
|
9,949
|
|
|
Settlements
|
|
|
1,929
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
—
|
|
|
|
|
|
|
|
|
(1)
|
Availability of market based information allowed the Company to reclassify all if its swap contracts tied to Southern Star prices from Level 3 to Level 2 during the
second quarter of 2011.
|
Additional Fair Value Disclosures —
The Company has 6,600 outstanding
shares of Series A Cumulative Redeemable Preferred Stock (“Series A Preferred Stock”) (see Note 9 — Redeemable Preferred Stock and Warrants) at September 30, 2012. The fair value and the carrying value of the Series A Preferred
Stock were $62.2 million and $56.7 million, respectively, at December 31, 2011, and $93.4 million and $66.6 million, respectively, at September 30, 2012. The fair value was determined by discounting the cash flows over the remaining life
of the securities utilizing a LIBOR interest rate and a risk premium of approximately 13.0% and 7.9% at December 31, 2011, and September 30, 2012, respectively, which was based on companies with similar leverage ratios to PostRock. The
Company has classified the valuation of these securities under Level 2 of the fair value hierarchy.
The Company’s debt
consists entirely of floating-rate facilities. The carrying amount of floating-rate debt approximates fair value because the interest rates paid on such debt are generally set for periods of nine months or shorter.
Note 6 — Equity Investment
The Company believes that its 26.5% voting interest in CEP at September 30, 2012, along with the right to appoint two directors to CEP’s Board provide it the ability to exercise significant
influence over the operating and financial policies of CEP. Rather than accounting for the investment under the equity method, the Company elected the fair value option to account for its interest in CEP. The fair value option was chosen as the
Company determined that the market price of CEP’s publicly traded interests provided a more accurate fair value measure of the Company’s investment in CEP. The Company has not elected the fair value option for any of its other assets and
liabilities.
The following table presents the mark-to-market gains (losses) on our equity investment, which are recorded as a
component of other income (expense) in the condensed consolidated statement of operations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
September 30,
|
|
|
Nine Months
Ended
September 30,
|
|
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
Mark to market gains (losses) on equity investment
|
|
$
|
(859
|
)
|
|
$
|
(2,111
|
)
|
|
$
|
(859
|
)
|
|
$
|
(4,578
|
)
|
F-11
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents summarized financial information of CEP (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
September 30,
|
|
|
Nine
Months Ended
September 30,
|
|
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
Revenues
|
|
$
|
31,443
|
|
|
$
|
6,495
|
|
|
$
|
71,671
|
|
|
$
|
42,067
|
|
|
Gross profit (loss) (1)
|
|
|
10,077
|
|
|
|
(9,650
|
)
|
|
|
13,194
|
|
|
|
(5,812
|
)
|
|
Net income (loss) from continuing operations
|
|
|
7,144
|
|
|
|
(11,163
|
)
|
|
|
4,459
|
|
|
|
(10,288
|
)
|
|
Net income (loss)
|
|
|
7,144
|
|
|
|
(11,163
|
)
|
|
|
4,459
|
|
|
|
(10,288
|
)
|
|
(1)
|
Equals revenues less operating expenses
|
Note 7 — Asset Retirement Obligations
The following table reflects the changes to asset retirement obligations for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
2011
|
|
|
2012
|
|
|
Asset retirement obligations at beginning of period
|
|
$
|
7,150
|
|
|
$
|
11,733
|
|
|
Liabilities incurred
|
|
|
163
|
|
|
|
127
|
|
|
Liabilities settled
|
|
|
(71
|
)
|
|
|
(101
|
)
|
|
Accretion
|
|
|
485
|
|
|
|
643
|
|
|
Divestitures (1)
|
|
|
(1
|
)
|
|
|
(1,737
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations at end of period
|
|
$
|
7,726
|
|
|
$
|
10,665
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The divestiture in 2012 was a result of the KPC sale.
|
Note 8 — Long-Term Debt
The following is a summary of long-term debt
at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2011
|
|
|
September 30,
2012
|
|
|
Borrowing Base Facility
|
|
$
|
190,000
|
|
|
$
|
102,855
|
|
|
Secured Pipeline Loan
|
|
|
3,000
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
193,000
|
|
|
|
102,855
|
|
|
Less current maturities included in current liabilities
|
|
|
3,000
|
|
|
|
102,855
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
190,000
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
The terms of the Company’s credit facilities are described within Note 10 of Item 8. Financial
Statement and Supplementary Data in the 2011 10-K and Note 8 of Part I, Item 1. Financial Statements in the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012. During the nine months ended September 30,
2012, the Company made $87.1 million in net payments on its Borrowing Base Facility. These payments included a payment of $12.0 million made during August 2012 utilizing proceeds from the issuance of equity to White Deer Energy L.P. and its
affiliates (“White Deer”) (see Note 9) and $51.5 million utilizing proceeds from the KPC sale (see Note 13). In addition, the Company made $3.0 million in payments on the Secured Pipeline Loan, which was fully retired in February
2012. Beginning in June 30, 2012, the Company classified the outstanding balance on the Borrowing Base Facility as a current liability to reflect the facility’s maturity date on June 30, 2013.
At September 30, 2012, the borrowing base was $120.0 million. With outstanding borrowings of $102.9 million and letters of credit of
$1.4 million, total utilization under the Borrowing Base Facility was $104.3 million and $15.7 million was available for additional borrowings at September 30, 2012.
The Company was in compliance with all of its financial covenants under the Borrowing Base Facility at September 30, 2012.
F-12
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As discussed within Note 10 of Item 8. Financial Statement and Supplementary
Data in the 2011 10-K, the Company settled its QER Loan in 2011 under terms that met accounting criteria to be classified as a troubled debt restructuring. The settlement in 2011 included an equity payment of $843,000 by issuing 141,186 shares of
the Company’s common stock to RBC. By evaluating the maximum sum of future cash flows that could be paid to the lender, RBC, the Company previously recorded gains on debt restructuring of $2.9 million and $1.6 million during the year ended
December 31, 2010, and during the second quarter of 2011, respectively. Upon the release of $5.7 million in escrowed proceeds from the Appalachian Basin sale in June 2012 (see Note 2), the Company retained $1.3 million and remitted $4.4 million
of these funds to RBC, representing the final payment in connection with the QER Loan. The $1.3 million of escrowed funds retained by the Company included recovery of the $843,000 payment to RBC made in 2011. As a result of the Company’s final
evaluation of all payments made to RBC in connection with the QER Loan, an additional gain on debt restructuring of $255,000 was recorded in June 2012.
Note 9 — Redeemable Preferred Stock and Warrants
On August 1,
2012, the Company issued an additional $12.0 million of equity to White Deer. In the transaction, the Company issued 3,076,923 shares of common stock at a price of $1.95 per share, the closing bid price from the prior day, for a total of $6.0
million in common stock. The Company also issued $6.0 million initial liquidation preference of Series A Preferred Stock along with warrants to purchase 3,076,923 shares of common stock at an exercise price of $1.95 a share. The $6.0 million
investment in Series A Preferred Stock and warrants was recognized on the Company’s condensed consolidated balance sheet based on the relative fair values of both financial instruments. As a result, the Company recorded a $4.0 million increase
to temporary equity related to the Series A Preferred Stock and a $2.0 million increase to additional paid in capital related to the warrants issued. The terms of the Series A Preferred Stock and warrants are substantially the same as those in White
Deer’s original September 2010 investment, which are further described in Note 12 of Part II, Item 8 in the 2011 10-K. However, the new warrants, including those that may be issued on future pay-in-kind dividends on this preferred
stock, are not coupled with a fractional share of Series B Voting Preferred Stock (and therefore have no voting right attached) and all of those warrants will have an exercise price of $1.95 a share, rather than the market price at the time of
issuance. White Deer also extended the period during which PostRock may pay-in-kind the dividends on all Series A Preferred Stock held by White Deer by 18 months to December 2014. Proceeds from the investment were used to reduce debt and provide
additional working capital.
As discussed above, prior to December 31, 2014, the Company may accrue dividends on its
Series A Preferred Stock rather than paying them in cash. Whenever dividends are accrued on a quarterly dividend payment date, the liquidation preference of the Series A Preferred Stock is increased by the amount of the accrued dividends and
additional warrants to purchase shares of PostRock common stock are issued. The Company records the increase in liquidation preference and the issuance of additional warrants by allocating their relative fair values to the amount of accrued
dividends. The allocation results in an increase to the Company’s temporary equity related to the Series A Preferred Stock and an increase to additional paid in capital related to the additional warrants issued. The increase to additional paid
in capital related to additional warrants issued for dividends paid in kind was $2.3 million during the nine months ended September 30, 2012.
F-13
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following tables describe the changes in temporary equity, currently consisting of
the Series A Preferred Stock (in thousands except share amounts), and in the outstanding warrants:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying Value of
Series
A Preferred
Stock
|
|
|
Number
of
Outstanding
Series A
Preferred
Shares
|
|
|
Liquidation Value
of
Series A Preferred
Stock
|
|
|
Number
of
Outstanding
Warrants
|
|
|
Weighted Average
Exercise
Price of
Warrants
|
|
|
December 31, 2011
|
|
$
|
56,736
|
|
|
|
6,000
|
|
|
$
|
69,759
|
|
|
|
21,566,245
|
|
|
$
|
3.23
|
|
|
Issuance
|
|
|
4,025
|
|
|
|
600
|
|
|
|
6,000
|
|
|
|
3,076,923
|
|
|
|
1.95
|
|
|
Accrued dividends
|
|
|
4,312
|
|
|
|
—
|
|
|
|
6,589
|
|
|
|
3,416,768
|
|
|
|
1.93
|
|
|
Accretion
|
|
|
1,540
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2012
|
|
$
|
66,613
|
|
|
|
6,600
|
|
|
$
|
82,348
|
|
|
|
28,059,936
|
|
|
$
|
2.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 10 — Equity and Earnings per Share
Share-Based Payments —
The Company recorded share based compensation credit of $157,000 and expense of $463,000 for the three
months ended September 30, 2011 and 2012, respectively. The credit for the three months ended September 30, 2011 was a result of forfeitures due to employee turnover. Share based compensation expense was $1.2 million and $1.6 million for
the nine months ended September 30, 2011 and 2012, respectively. Total share-based compensation to be recognized on unvested stock awards and options at September 30, 2012, is $2.1 million over a weighted average period of 1.32 years. The
following table summarizes option and restricted awards granted during 2012 and their associated valuation assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
awards
granted
|
|
|
Fair value per
option
or share
|
|
|
Exercise price
|
|
|
Risk free rate
|
|
|
Volatility
|
|
|
Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter 2012 employee awards (1)
|
|
|
95,000
|
|
|
$
|
1.69
|
|
|
$
|
2.93
|
|
|
|
0.9
|
%
|
|
|
76.1
|
%
|
|
Second quarter 2012 employee awards (1)
|
|
|
134,230
|
|
|
$
|
1.88
|
|
|
$
|
3.09
|
|
|
|
1.28
|
%
|
|
|
74.3
|
%
|
|
Restricted Stock Awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter 2012 employee awards (2)
|
|
|
153,800
|
|
|
$
|
3.70
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
Second quarter 2012 employee awards (1)
|
|
|
141,100
|
|
|
$
|
3.09
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
Restricted Stock Units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second quarter 2012 director awards (3)
|
|
|
120,000
|
|
|
$
|
2.37
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
Third quarter 2012 director awards (4)
|
|
|
29,967
|
|
|
$
|
1.53
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
|
n/a
|
|
|
(1)
|
Awards vest ratably over a three year period.
|
|
(2)
|
Awards vest in one year.
|
|
(3)
|
Awards vest in one year and are deliverable to the participant on the earlier of the fifth anniversary of the grant date or the date of participant’s separation
from the Company.
|
|
(4)
|
Awards vest immediately and are deliverable to the participant on the earlier of the fifth anniversary of the grant date or the date of participant’s separation
from the Company.
|
F-14
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Income/(Loss) per Share —
A reconciliation of the denominator (number of
shares) used in the basic and diluted per share calculations for the periods indicated is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine months Ended September 30,
|
|
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
Denominator for basic earnings per share
|
|
|
9,009,109
|
|
|
|
14,477,241
|
|
|
|
8,528,020
|
|
|
|
12,702,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of potentially dilutive securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested share-based awards
|
|
|
130,591
|
|
|
|
—
|
|
|
|
157,238
|
|
|
|
—
|
|
|
Warrants
|
|
|
6,843,407
|
|
|
|
—
|
|
|
|
8,004,358
|
|
|
|
—
|
|
|
Stock options
|
|
|
26,525
|
|
|
|
—
|
|
|
|
63,146
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings per share
|
|
|
16,009,632
|
|
|
|
14,477,241
|
|
|
|
16,752,762
|
|
|
|
12,702,079
|
|
|
Securities excluded from earnings per share calculation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested share-based awards
|
|
|
—
|
|
|
|
832,977
|
|
|
|
—
|
|
|
|
832,977
|
|
|
Antidilutive stock options
|
|
|
420,750
|
|
|
|
1,133,005
|
|
|
|
420,750
|
|
|
|
1,133,005
|
|
|
Warrants
|
|
|
1,293,878
|
|
|
|
27,149,235
|
|
|
|
1,293,878
|
|
|
|
27,149,235
|
|
Common Stock Issuance —
On February 9, 2012, the Company issued 2,180,233 shares of its
common stock to White Deer for proceeds of $7.5 million, which were used to retire the Secured Pipeline Loan and for other general corporate purposes. On August 1, 2012, an additional 3,076,923 shares of common stock were issued to White Deer
for proceeds of $6.0 million.
The Company has an effective $100 million universal shelf registration statement under which it
has been selling common shares pursuant to an at-the-market issuance sales agreement with a sales agent. Including sales through October 31, 2012, the Company has sold 90,927 common shares for gross proceeds of $191,000 in the current year.
Note 11 — Commitments and Contingencies
Litigation
— The Company is subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting its business. It records a liability related to its legal
proceedings and claims when it has determined that it is probable that it will be obligated to pay and the related amount can be reasonably estimated. Except for those legal proceedings listed below, it believes there are no pending legal
proceedings in which it is currently involved which, if adversely determined, would have a material adverse effect on its financial position, results of operations or cash flow.
During 2011, the Company was involved in various royalty owner lawsuits in Kansas and Oklahoma as further described in Note 14 of Part
II, Item 8 in the 2011 10-K. These lawsuits were settled in 2011. The Company made a settlement payment of $3.0 million related to the Kansas lawsuit in January 2012 with an additional payment of $4.5 million to be made by January 31,
2013. The Company has accrued $4.5 million at September 30, 2012, related to its outstanding litigation which represents the present value of the remaining payment on its Kansas royalty lawsuit settlement.
Contractual Commitments
— The Company has numerous contractual commitments in the ordinary course of business including debt
service requirements, operating leases and purchase obligations. During the nine months ended September 30, 2012, the Company entered into new contractual commitments for data storage services, compressors used in its gathering system and fees
related to the sale of the KPC pipeline. As a result, the $3.4 million minimum amount of these contracts over a span of five years would be an increase to the amount included in the Company’s outstanding contractual commitments table at
December 31, 2011.
F-15
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Other than the contractual commitments discussed above and debt repayments during the
nine months ended September 30, 2012, there were no material changes to the Company’s contractual commitments since December 31, 2011.
Note 12 — Impairment of Oil and Gas Properties
At the end of each
quarterly period, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the full cost ceiling, computed as the sum of the estimated future net revenues from proved reserves using twelve-month
average prices discounted at 10%, and adjusted for related income tax effects (ceiling test). Under full cost accounting rules, any ceiling test write-down of oil and natural gas properties may not be reversed in subsequent periods. Since the
Company does not designate its derivative financial instruments as hedges, it is not allowed to use the impacts of the derivative financial instruments in its ceiling test computation. As a result, decreases in commodity prices which contribute to
ceiling test write-downs may be offset by mark-to-market gains which are not reflected in the Company’s ceiling test results.
The base for the Company’s spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. At September 30, 2012, the ceiling test computation, utilizing a twelve-month average price
on that day, resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the September 30, 2012 present value of future net revenues. As a result of this difference, we recorded a
ceiling test impairment of $4.3 million for the three and nine months ended September 30, 2012. The Company may face further ceiling test write-downs in future periods, depending on the level of commodity prices, drilling results and well
performance.
The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties
inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering
and geological interpretation and judgment. Results of drilling, testing, production and changes in economics related to the properties subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are
often different from the quantities of oil and natural gas that are ultimately recovered.
Note 13 — Discontinued Operations
On September 28, 2012, the Company, PostRock Energy Services Corporation, a wholly owned subsidiary of the Company
(“Seller”), and KPC entered into and simultaneously closed a Purchase Agreement (the “Purchase Agreement”) with MV pursuant to which the Seller sold all the equity of KPC to MV for a gross purchase price to be paid at closing of
$53.5 million. After an adjustment for working capital as set forth in the Purchase Agreement, the Company received $52.9 million in cash at closing while an additional $500,000 was set aside in escrow to be released to the Company upon the
acceptable cleanup of a former KPC property now owned by another subsidiary of the Company. MV also agreed to make additional payments of $1.0 million for each of the next four years if qualified EBITDA (as defined in the Purchase Agreement) of KPC
for that year exceeds a target amount. KPC owns a 1,120 mile interstate natural gas pipeline that transports natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City, which formerly comprised the Company’s pipeline
segment.
The carrying value of KPC’s net assets sold was $57.0 million which resulted in a loss on sale of $5.6 million
recorded during the third quarter of 2012. The loss on sale included $2.0 million in closing-related costs comprised of $1.0 million in legal, professional, and investment banking fees, $505,000 of severance and $500,000 in site cleanup costs. The
operating results of the KPC pipeline are classified as discontinued operations and are presented in a separate line in the consolidated statement of operations for all periods presented. Prior to the classification as a discontinued operation, the
Company had reported this business as a separate segment under the heading “Pipeline.”
F-16
POSTROCK ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
To enhance comparison of the balance sheet, the Company has separately disclosed the
assets and liabilities of KPC at December 31, 2011. The table below sets forth the related assets and liabilities (in thousands):
|
|
|
|
|
|
|
|
|
December 31,
2011
|
|
|
Accounts receivable—trade, net
|
|
$
|
1,338
|
|
|
Other receivables
|
|
|
103
|
|
|
Inventory
|
|
|
107
|
|
|
Other
|
|
|
37
|
|
|
|
|
|
|
|
|
Total current assets of discontinued operations
|
|
$
|
1,585
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline assets, net
|
|
$
|
59,088
|
|
|
Other property and equipment, net
|
|
|
261
|
|
|
Contract-related intangible asset
|
|
|
685
|
|
|
|
|
|
|
|
|
Total noncurrent assets of discontinued operations
|
|
$
|
60,034
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
563
|
|
|
Accrued expenses and other
|
|
|
373
|
|
|
|
|
|
|
|
|
Total current liabilities of discontinued operations
|
|
$
|
936
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$
|
1,646
|
|
|
|
|
|
|
|
|
Total noncurrent liabilities of discontinued operations
|
|
$
|
1,646
|
|
|
|
|
|
|
|
The following table discloses the results of discontinued operations related to KPC (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
September 30,
|
|
|
Nine
months Ended
September 30,
|
|
|
|
|
2011
|
|
|
2012
|
|
|
2011
|
|
|
2012
|
|
|
Interstate pipeline revenue
|
|
$
|
2,501
|
|
|
$
|
2,692
|
|
|
$
|
8,140
|
|
|
$
|
8,934
|
|
|
Pipeline expense
|
|
|
(1,132
|
)
|
|
|
(1,178
|
)
|
|
|
(4,148
|
)
|
|
|
(2,825
|
)
|
|
Depreciation and amortization
|
|
|
(881
|
)
|
|
|
(845
|
)
|
|
|
(2,702
|
)
|
|
|
(2,537
|
)
|
|
Loss on disposal of assets (1)
|
|
|
(4
|
)
|
|
|
(5,591
|
)
|
|
|
(1
|
)
|
|
|
(5,586
|
)
|
|
General and administrative expenses
|
|
|
(289
|
)
|
|
|
(322
|
)
|
|
|
(876
|
)
|
|
|
(945
|
)
|
|
Interest expense
|
|
|
(126
|
)
|
|
|
—
|
|
|
|
(459
|
)
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations before income taxes
|
|
|
69
|
|
|
|
(5,244
|
)
|
|
|
(46
|
)
|
|
|
(3,004
|
)
|
|
Income taxes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income (loss) from discontinued operations
|
|
$
|
69
|
|
|
$
|
(5,244
|
)
|
|
$
|
(46
|
)
|
|
$
|
(3,004
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Includes a loss of $5.6 million from the disposal of KPC for the three and nine month periods ended September 30, 2012.
|
Note 14 — Subsequent Events
On November 5, 2012, the Company settled its natural gas hedges held for delivery between July 2013 and December 2013 for proceeds of $14.8 million. The proceeds were used to repay outstanding
borrowings under the Company’s Borrowing Base Facility.
In connection with the borrowing base redetermination of the
Borrowing Base Facility, originally scheduled to be effective on October 31, 2012, based on our oil and gas reserves at June 30, 2012, the Company expects the borrowing base to be $98.0 million, effective as of November 9, 2012. Subsequent
to the application of proceeds from the hedge settlement discussed above, the Company’s total utilization under the facility was below $98.0 million.
F-17
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Overview
PostRock Energy Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. We manage our business in one
segment, production. Our primary production activity is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma. We also have minor oil producing properties in Oklahoma and oil and gas producing properties
in the Appalachian Basin. We previously owned a 1,120 mile interstate natural gas pipeline, which transported natural gas from northern Oklahoma and western Kansas to Wichita and Kansas City. We sold the interstate pipeline in September 2012
and are reporting its results as a discontinued operation on our financial statements. Unless the context requires otherwise, references to “PostRock,” the “Company,” “we,” “us” and “our” refer to
PostRock Energy Corporation and its consolidated subsidiaries.
The following discussion should be read together with the
unaudited consolidated financial statements and related notes included elsewhere herein and with our annual report on Form 10-K for the year ended December 31, 2011.
2012 Drilling Program Update
During 2012, we have performed 87
recompletions, most of which were to increase oil production. We have also drilled 12 oil wells of which five have been brought online. Capital spending during the nine months ended September 30, 2012, included $6.4 million on oil directed
drilling and recompletions, $2.0 million on vehicle and equipment replacement, $1.2 million to connect two sections of our gathering system in an effort to improve production, $300,000 to complete our consolidation and upgrade of facilities in
the Cherokee Basin, $119,000 to extend leases, $836,000 on information technology and $1.2 million on various other projects related to compressor optimization and field efficiency. Prior to its sale in September 2012, we also incurred $638,000 of
capital expenditures on our interstate pipeline. Our capital spending for the remainder of 2012 is subject to available capital as discussed below in “
Sources of Liquidity in 2012 and Capital Requirements.
”
The significant reduction in natural gas prices at the end of 2011 has continued into 2012. Prices fell below $2.00 per MMbtu in April
2012 and are currently around $3.50 per MMbtu. Even with the recent improvement, prices remain depressed at a level that may not encourage dry gas development for some time. As a result, we have curtailed all capital expenditures related to natural
gas and have directed our drilling capital to oil development opportunities. This change in capital development focus is a significant contributing factor to our 12.7% decline in gas production and 28.4% increase in oil production when comparing the
three month periods ending September 30, 2011 and 2012.
Since February 2012, we have performed 75 Cherokee Basin
recompletions targeting behind-pipe oil potential. Of these, 50 have been producing long enough to determine their results. Peak production rates from successful recompletions have averaged 7 gross barrels of oil per day. Recompletion projects
currently have a 50% success rate at finding new oil production. The cash cost of a successful recompletion is approximately $67,000, including a new tank battery, and the cash cost of an unsuccessful recompletion is $22,000. Based on current prices
and our pattern of capital costs and success rate, early results indicate our recompletion program should yield a rate of return greater than 45%. For the remainder of 2012 we plan to complete 27 oil recompletions and 16 new oil wells at a total
cost of approximately $3 million.
1
Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2012
The following table presents financial and operating data for the periods indicated as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
September 30,
|
|
|
Increase/
(Decrease)
|
|
|
|
|
2011
|
|
|
2012
|
|
|
|
|
|
($ in thousands except per unit data)
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
18,889
|
|
|
$
|
10,819
|
|
|
$
|
(8,070
|
)
|
|
|
(42.7
|
)%
|
|
Crude oil sales
|
|
$
|
1,654
|
|
|
$
|
2,232
|
|
|
$
|
578
|
|
|
|
34.9
|
%
|
|
Gathering revenue
|
|
$
|
1,383
|
|
|
$
|
646
|
|
|
$
|
(737
|
)
|
|
|
(53.3
|
)%
|
|
Production expense
|
|
$
|
11,845
|
|
|
$
|
9,917
|
|
|
$
|
(1,928
|
)
|
|
|
(16.3
|
)%
|
|
Depreciation, depletion and amortization
|
|
$
|
5,874
|
|
|
$
|
7,321
|
|
|
$
|
1,447
|
|
|
|
24.6
|
%
|
|
Impairment of oil and gas assets
|
|
$
|
—
|
|
|
$
|
4,309
|
|
|
$
|
4,309
|
|
|
|
*
|
|
|
Gain (loss) on disposal of assets
|
|
$
|
32
|
|
|
$
|
(64
|
)
|
|
$
|
(96
|
)
|
|
|
*
|
|
|
Production Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil production (Bbls)
|
|
|
19,503
|
|
|
|
25,035
|
|
|
|
5,532
|
|
|
|
28.4
|
%
|
|
Natural gas production (Mmcf)
|
|
|
4,611
|
|
|
|
4,025
|
|
|
|
(586
|
)
|
|
|
(12.7
|
)%
|
|
Total production (Mmcfe)
|
|
|
4,728
|
|
|
|
4,176
|
|
|
|
(552
|
)
|
|
|
(11.7
|
)%
|
|
Average daily production (Mmcfe/d)
|
|
|
51.4
|
|
|
|
45.4
|
|
|
|
(6.0
|
)
|
|
|
(11.7
|
)%
|
|
Average Sales Price per Unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (Mcf)
|
|
$
|
4.10
|
|
|
$
|
2.69
|
|
|
$
|
(1.41
|
)
|
|
|
(34.4
|
)%
|
|
Oil(Bbl)
|
|
$
|
84.81
|
|
|
$
|
89.15
|
|
|
$
|
4.34
|
|
|
|
5.1
|
%
|
|
Natural Gas Equivalent (Mcfe)
|
|
$
|
4.35
|
|
|
$
|
3.13
|
|
|
$
|
(1.22
|
)
|
|
|
(28.1
|
)%
|
|
Average Unit Costs per Mcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expense
|
|
$
|
2.51
|
|
|
$
|
2.38
|
|
|
$
|
(0.13
|
)
|
|
|
(5.2
|
)%
|
|
Depreciation, depletion and amortization
|
|
$
|
1.24
|
|
|
$
|
1.75
|
|
|
$
|
0.51
|
|
|
|
41.1
|
%
|
Natural gas
sales decreased $8.1 million, or 42.7%, from $18.9 million during the three months ended September 30, 2011, to $10.8 million during the three months ended September 30, 2012. Lower natural gas prices resulted in decreased revenues of
$5.7 million and lower gas production volumes decreased revenues by $2.4 million. The decline in gas production was the result of suspended gas development during the low gas price environment in 2012. These decreases were slightly offset by
increased oil revenue of $578,000, which increased from $1.7 million during the three months ended September 30, 2011, to $2.2 million during the three months ended September 30, 2012. The increase was primarily driven by a 28.4% increase
in crude oil volumes sold. Our average realized natural gas price decreased from $4.10 per Mcf for the three months ended September 30, 2011, to $2.69 per Mcf for the three months ended September 30, 2012. During this time period, our
average realized crude oil price increased from $84.81 per barrel to $89.15 per barrel.
Gathering revenue decreased $737,000,
or 53.3%, from $1.4 million for the three months ended September 30, 2011, to $646,000 for the three months ended September 30, 2012. The decrease is primarily due to the settlement of the royalty lawsuits discussed below, which lowered
the rates we receive for gathering royalty interest gas coupled with lower production volumes.
Production expense consists of
lease operating expenses, severance and ad valorem taxes (“production taxes”) and gathering expense. Production expense decreased $1.9 million, or 16.3%, from $11.8 million for the three months ended September 30, 2011, to $9.9
million for the three months ended September 30, 2012. The decrease was primarily due to lower production taxes of approximately $732,000, lower labor costs of $727,000, lower gas gathering costs of $153,000, lower repair and maintenance
expenses of $512,000, lower vehicle and equipment costs of $371,000 and a downward adjustment to our inventory reserve of $93,000, partially offset by a reduction in capitalized expenses of $672,000. Production expense was $2.51 per Mcfe for
the three months ended September 30, 2011, as compared to $2.38 per Mcfe for the three months ended September 30, 2012, as the 16.3% reduction in expense was partially offset by the 11.7% decline in production.
2
Depreciation, depletion and amortization increased $1.4 million, or 24.6%, from $5.9 million
during the three months ended September 30, 2011, to $7.3 million during the three months ended September 30, 2012. On a per unit basis, we had an increase of $0.51 per Mcfe from $1.24 per Mcfe during the three months ended
September 30, 2011, to $1.75 per Mcfe during the three months ended September 30, 2012. The increase was primarily due to a higher depletion rate as a result of a decrease in oil and gas reserves brought about by lower natural gas prices
partially offset by lower production volumes in the current quarter.
Impairment of our oil and gas properties was $4.3
million during the three months ended September 30, 2012 while none was required in the prior year quarter. Each quarter, we are required to assess the recoverability of the carrying value of our oil and gas properties against the present value
of their future expected net revenues utilizing a twelve month average first of the month price for oil and natural gas. Driven by a 30.7% decrease in the third quarter prices compared to the prior year third quarter, the twelve month average
natural gas price decreased significantly. This resulted in the carrying value of our oil and natural gas properties exceeding the present value under the prescribed methodology. Natural gas prices during the fourth quarter of 2011 ranged
between $3.53 per MMBtu and $3.68 per MMBtu, averaging $3.63 per MMBtu. Thus far, prices during the fourth quarter of 2012 have averaged $3.30 per MMBtu. Absent an increase in natural gas prices, we may be required to record an additional
impairment at year-end.
General and administrative expenses decreased $457,000, or 11.6%, from $4.0 million during the three
months ended September 30, 2011, to $3.5 million during the three months ended September 30, 2012. The 2011 period included a $757,000 charge related to the closure of our Houston office while the 2012 period included a $435,000 severance
charge as we restructured our Oklahoma City office. Excluding these charges, general and administrative expenses would have been $135,000 lower in the current quarter compared to the prior year quarter. The decrease was primarily due to lower wages
and bonuses of $373,000, lower legal, accounting and audit fees of approximately $278,000 and lower rent of $69,000 partially offset by higher stock compensation expense of $575,000 as a result of the forfeiture of unvested grants in the prior year
quarter.
Litigation reserve expense was $2.0 million for the three months ended September 30, 2011, with none recorded
for the current quarter. The 2011 expense was recorded to increase the litigation reserve for our Kansas royalty owner lawsuit, which was settled in 2011 for $7.5 million. The settlement included $3.0 million paid in January 2012 and $4.5 million to
be paid by January 31, 2013. A separate royalty owner lawsuit in Oklahoma was settled in 2011 for $5.6 million. As part of these settlements, all ambiguity in the calculation of prospective as well as prior royalties in our lease agreements was
eliminated.
Other income (expense) consists primarily of gains (losses) from derivative instruments, gain (loss) from equity
investment and net interest expense. We recorded unrealized gains of $4.7 million and unrealized losses of $6.5 million on our derivative contracts for the three months ended September 30, 2011 and 2012, respectively. We recorded realized gains
of $7.3 million and $2.7 million on our derivative contracts for the three months ended September 30, 2011 and 2012, respectively. We recorded mark-to-market losses on our equity investment in Constellation Energy Partners LLC (“CEP”)
of $859,000 and $2.1 million for the three months ended September 30, 2011 and 2012, respectively. Interest expense, net, was $2.5 million during the three months ended September 30, 2011, and $2.6 million during the three months ended
September 30, 2012. Increased interest expense was the result of accretion charges to increase the present value of our litigation reserve.
Discontinued operations includes the operating results related to our interstate pipeline, including the loss we incurred on its sale in September 2012. We recorded income from discontinued operations of
$69,000 for the three months ended September 30, 2011, compared to a loss $5.2 million for the three months ended September 30, 2012. The loss in 2012 was driven by the $5.6 million loss on the sale of the pipeline. We received
proceeds of $53.4 million on the sale while the carrying value of assets sold was $57.0 million, and $2.0 million in selling costs were incurred. The sale is discussed further in
Liquidity and Capital Resources
below.
3
Nine months Ended September 30, 2011 Compared to the Nine months Ended September 30, 2012
The following table presents financial and operating data for the periods indicated as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months
Ended
September 30,
|
|
|
Increase/
(Decrease)
|
|
|
|
|
2011
|
|
|
2012
|
|
|
|
|
|
($ in thousands except per unit data)
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
57,052
|
|
|
$
|
31,069
|
|
|
$
|
(25,983
|
)
|
|
|
(45.5
|
)%
|
|
Crude oil sales
|
|
$
|
5,253
|
|
|
$
|
6,254
|
|
|
$
|
1,001
|
|
|
|
19.1
|
%
|
|
Gathering revenue
|
|
$
|
4,272
|
|
|
$
|
1,819
|
|
|
$
|
(2,453
|
)
|
|
|
(57.4
|
)%
|
|
Production expense
|
|
$
|
35,685
|
|
|
$
|
32,117
|
|
|
$
|
(3,568
|
)
|
|
|
(10.0
|
)%
|
|
Depreciation, depletion and amortization
|
|
$
|
17,780
|
|
|
$
|
20,423
|
|
|
$
|
2,643
|
|
|
|
14.9
|
%
|
|
Impairment of oil and gas properties
|
|
$
|
—
|
|
|
$
|
4,309
|
|
|
$
|
4,309
|
|
|
|
*
|
|
|
Gain (loss) on disposal of assets
|
|
$
|
12,386
|
|
|
$
|
(226
|
)
|
|
$
|
(12,612
|
)
|
|
|
*
|
|
|
Production Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil production (Bbls)
|
|
|
57,637
|
|
|
|
67,772
|
|
|
|
10,135
|
|
|
|
17.6
|
%
|
|
Natural gas production (Mmcf)
|
|
|
13,796
|
|
|
|
12,454
|
|
|
|
(1,342
|
)
|
|
|
(9.7
|
)%
|
|
Total production (Mmcfe)
|
|
|
14,142
|
|
|
|
12,861
|
|
|
|
(1,281
|
)
|
|
|
(9.1
|
)%
|
|
Average daily production (Mmcfe/d)
|
|
|
51.8
|
|
|
|
46.9
|
|
|
|
(4.9
|
)
|
|
|
(9.5
|
)%
|
|
Average Sales Price per Unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (Mcf)
|
|
$
|
4.14
|
|
|
$
|
2.49
|
|
|
$
|
(1.65
|
)
|
|
|
(39.9
|
)%
|
|
Oil(Bbl)
|
|
$
|
91.14
|
|
|
$
|
92.28
|
|
|
$
|
1.14
|
|
|
|
1.3
|
%
|
|
Natural Gas Equivalent (Mcfe)
|
|
$
|
4.41
|
|
|
$
|
2.90
|
|
|
$
|
(1.51
|
)
|
|
|
(34.2
|
)%
|
|
Average Unit Costs per Mcfe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expense
|
|
$
|
2.52
|
|
|
$
|
2.50
|
|
|
$
|
(0.02
|
)
|
|
|
(0.1
|
)%
|
|
Depreciation, depletion and amortization
|
|
$
|
1.26
|
|
|
$
|
1.59
|
|
|
$
|
0.33
|
|
|
|
26.2
|
%
|
Natural gas
sales decreased $26.0 million, or 45.5%, from $57.1 million during the nine months ended September 30, 2011, to $31.1 million during the nine months ended September 30, 2012. Lower natural gas prices resulted in decreased revenues of
$20.4 million and lower gas production volumes decreased revenues by $5.6 million. The decline in gas production was the result of suspended gas development during the low gas price environment in 2012. These decreases were slightly offset by
increased oil revenue of $1.0 million, which increased from $5.3 million during the nine months ended September 30, 2011, to $6.3 million during the nine months ended September 30, 2012. The increase was primarily driven by a 17.6%
increase in crude oil volumes sold. Our average realized natural gas price decreased from $4.14 per Mcf for the nine months ended September 30, 2011, to $2.49 per Mcf for the nine months ended September 30, 2012. Our average realized crude
oil price was relatively flat across the two periods.
Gathering revenue decreased $2.5 million, or 57.4%, from $4.3 million
for the nine months ended September 30, 2011, to $1.8 million for the nine months ended September 30, 2012. The decrease is primarily due to the settlement of royalty lawsuits which lowered the rates that we receive for gathering
royalty interest gas coupled with lower production volumes.
Production expense decreased $3.6 million, or 10.0%, from $35.7
million for the nine months ended September 30, 2011, to $32.1 million for the nine months ended September 30, 2012. The 2012 period included a $368,000 charge related to our March 2012 field reorganization. Excluding this charge,
production expense was $3.9 million lower than the prior year period. The decrease was in part due to field optimization projects we began in the latter half of 2011, which resulted in decreased labor, vehicle and equipment costs of $3.0 million and
decreased gathering costs of $467,000. Also contributing to the decrease was a reduction in production taxes of $2.4 million primarily due to lower gas prices and production. These reductions were offset by decreased capitalized expenses of $2.0
million due to reduced drilling activity. Excluding the field reorganization charge, production expense was $2.47 per Mcfe for the nine months ended September 30, 2012, compared to $2.52 for the nine months ended September 30, 2011.
4
Depreciation, depletion and amortization increased $2.6 million, or 14.9%, from $17.8
million during the nine months ended September 30, 2011, to $20.4 million during the nine months ended September 30, 2012. On a per unit basis, we had an increase of $0.33 per Mcfe from $1.26 per Mcfe during the nine months ended
September 30, 2011, to $1.59 per Mcfe during the nine months ended September 30, 2012. The increase was primarily due to a higher depletion rate as a result of a decrease in oil and gas reserves brought about by lower natural gas prices
partially offset by lower production volumes in the current year.
As further described above, impairment of our oil and gas
properties was $4.3 million during the nine months ended September 30, 2012 while none was required in the prior year period.
General and administrative expenses decreased $2.1 million, or 15.5%, from $13.4 million during the nine months ended September 30, 2011, to $11.3 million during the nine months ended
September 30, 2012. The 2011 period included a $757,000 charge related to the closure of our Houston office and a workman’s compensation payout of $310,000 while the 2012 period included a $435,000 severance charge as we restructured our
Oklahoma City office. Excluding these charges, general and administrative expenses would have been $1.4 million lower in the current year period compared to the prior year period. The cost reduction is due to lower wages, bonuses and benefits of
$814,000 and lower legal costs of $840,000 as we settled all material lawsuits in 2011. These reductions were offset by a $326,000 increase in stock compensation due to higher forfeitures of unvested grants in the prior year compared to the current
year.
Litigation reserve expense was $11.6 million for the nine months ended September 30, 2011, with none recorded for
the nine months ended September 30, 2012. The expense in 2011 was recorded to increase our litigation reserve to the estimated potential cost to resolve royalty owner lawsuits pending in Oklahoma and Kansas at the time. As discussed above,
these lawsuits were settled in 2011.
We recorded a gain on disposal of assets of $12.4 million during the nine months ended
September 30, 2011, compared to a loss of $226,000 during the current year period. The gain in 2011 was primarily due to the second and third phases of the Appalachia Basin sale. Gross proceeds from both phases were $16.6 million. The loss in
2012 was primarily due to a post-closing adjustment related to our Appalachian Basin asset sale.
Other income (expense)
consists primarily of gains (losses) from derivative instruments, gain (loss) from equity investment, gain on forgiveness of debt and net interest expense. We recorded unrealized losses of $6.5 million and $25.4 million on our derivative contracts
for the nine months ended September 30, 2011 and 2012, respectively. We recorded realized gains of $23.2 million and $33.4 million on our derivative contracts for the nine months ended September 30, 2011 and 2012, respectively. We recorded
mark-to-market losses on our equity investment in CEP of $859,000 and $4.6 million during the nine months ended September 20, 2011 and 2012, respectively. Gain on forgiveness of debt was $1.6 million and $255,000 for the nine months ended
September 30, 2011 and 2012, respectively. The gains were a result of the settlement of our QER Loan under a troubled debt restructuring as discussed in
Liquidity and Capital Resources
below. Interest expense, net, was $7.5 million
during the nine months ended September 30, 2011, and $7.8 million during the nine months ended September 30, 2012. Increased interest expense was the result of accretion charges to increase the present value of our litigation reserve.
We recorded losses from discontinued operations of $46,000 and $3.0 million for the nine months ended September 30, 2011
and 2012, respectively. The loss on the sale of the interstate pipeline of $5.6 million in the current year was partially offset by increased pipeline revenue, lower pipeline expenses and lower interest charges compared to the prior year period.
Pipeline revenue was $794,000 higher as a result of increased throughput from growing gas volumes associated with oil production in Osage County, Oklahoma. Pipeline expense was $1.3 million lower in the current year as the prior year included costs
for a capacity lease that expired in October 2011, an external gas leak that occurred during the first quarter of 2011 and contract services that we did not require in the current year. Interest charges in the current year were lower than the prior
year as the outstanding balance on our Secured Pipeline Loan was paid off in February 2012.
Liquidity and Capital Resources
Cash flows from operating activities have historically been driven by the quantities of our production, the prices
received from the sale of this production, and from our pipeline revenue. Prices of oil and gas have
5
historically been very volatile and can significantly impact the cash received from the sale of our production. Use of derivative financial instruments help mitigate this price volatility. Cash
expenses also impact our operating cash flow and consist primarily of production operating costs, production taxes, interest on our indebtedness and general and administrative expenses.
Our primary sources of liquidity for the nine months ended September 30, 2012, were proceeds from selling our interstate pipeline,
cash generated from our hedging activities, proceeds from issuing common and preferred stock to White Deer Energy L.P. and its affiliates (“White Deer”), cash flows from operations and borrowings under our borrowing base credit facility.
We also received $1.3 million of cash from the release of escrowed proceeds from our Appalachia Basin sale. At September 30, 2012, we had decreased our debt by $90.1 million from December 31, 2011.
Cash Flows from Operating Activities
Cash flows provided by operating activities were essentially flat at $29.5 million and $29.4 million for the nine months ended September 30, 2011 and 2012, respectively. Decreased cash flows from
declining revenues were offset by lower production and pipeline operating costs, lower general and administrative expenses, lower legal settlement payments and higher proceeds from our commodity derivatives.
Cash Flows from Investing Activities
Cash flows used in investing activities were $17.9 million for the nine months ended September 30, 2011, compared to cash received of $40.9 million for the nine months ended September 30, 2012.
Capital expenditures were $23.4 million and $12.3 million for the nine months ended September 30, 2011 and 2012, respectively. The reduction in capital expenditures was a result of depressed natural gas prices in 2012 which prompted us to
curtail gas related projects early in the year and redirect our focus toward oil related projects. We received proceeds from the sale of assets of $10.7 million and $53.2 for nine months ended September 30, 2011 and 2012, respectively. Proceeds
from the sale of assets in 2011 were primarily from the second and third phases of our Appalachia Basin asset sale while proceeds in 2012 were from the sale of our interstate pipeline. In September 2011, we purchased an equity interest in CEP for a
gross purchase price of $11.5 million, which included $6.6 million in cash and the remainder in equity securities. The following table sets forth our capital expenditures, including costs we have incurred but not paid, by major categories for the
nine months ended September 30, 2012 (in thousands):
|
|
|
|
|
|
|
|
|
Nine Months
Ended
September 30, 2012
|
|
|
Capital expenditures
|
|
|
|
|
|
Leasehold acquisition
|
|
$
|
119
|
|
|
Development
|
|
|
7,637
|
|
|
Pipelines (1)
|
|
|
638
|
|
|
Other items
|
|
|
4,337
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
12,731
|
|
|
|
|
|
|
|
|
(1)
|
Relates to the discontinued operations of the interstate pipeline which was sold in September 2012
|
Cash Flows from Financing Activities
Cash flows used in financing activities were $12.3 million for the nine months ended September 30, 2011, as compared to $70.5 million for the nine months ended September 30, 2012. Debt
repayments were $15.3 million and $90.1 million for the nine months ended September 30, 2011 and 2012, respectively. The repayment of debt during the 2011 period was partially offset by $3.0 million in borrowings. During the nine months
ended September 30, 2012, we issued $13.5 million of common stock and $6.0 million of preferred stock and warrants to White Deer while incurring $81,000 of issuance costs. We also issued $182,000 of common stock during this period under an
at-the-market sales agreement as discussed below.
6
Sources of Liquidity in 2012 and Capital Requirements
We rely on our cash flows from operating activities as a source of internally generated liquidity. During the past three years, our cash
flows from operating activities have been sufficient to fund our investing activities. Our long-term ability to generate liquidity internally depends in part on our ability to hedge future production at attractive prices as well as our ability to
control operating expenses. This has become especially critical in light of current depressed natural gas prices. To a lesser extent, we have in the past relied on the sale of our non-core assets to generate liquidity. During 2010 and 2011, we sold
several parcels of production assets in the Appalachian Basin. In September 2012, we sold our interstate pipeline. Proceeds from these non-core asset sales were primarily utilized to repay outstanding debt. From time to time, we may also issue
equity as an external source of liquidity. On February 9, 2012, we issued 2,180,233 shares of our common stock to White Deer for proceeds of $7.5 million. On August 1, 2012, we issued to White Deer an additional 3,076,923 shares of our
common stock at $1.95 per share, $6.0 million initial liquidation preference of our Series A Cumulative Redeemable Preferred Stock and warrants to purchase 3,076,923 shares of common stock at an exercise price of $1.95 per share. Total proceeds from
White Deer for the August 1 issuance were $12.0 million. The net proceeds from issuing equity to White Deer in 2012 were utilized to repay outstanding debt and for working capital purposes.
During April 2012 we repriced the portion of our natural gas swap contracts expected to settle in June, July and August of 2012 to market
prices for proceeds of $10.8 million. The proceeds were utilized to reduce our debt.
On September 28, 2012, we
consummated the sale of our interstate pipeline subsidiary PostRock KPC Pipeline, LLC (“KPC”) to MV Pipelines, LLC (“MV”) for a gross purchase price to be paid at closing of $53.5 million. After an adjustment for working capital,
we received $52.9 million in cash at closing, and an additional $500,000 was deposited in escrow to be released to us upon acceptable cleanup of a site previously owned by KPC. MV also agreed to make additional payments of $1.0 million for each of
the next four years if qualified EBITDA, as defined in the purchase agreement, of KPC for that year exceeds a target amount.
In conjunction with closing the KPC sale, we utilized proceeds of $51.5 million to repay outstanding borrowings under our secured
borrowing base revolving credit facility. Upon the repayment, our borrowing base was reduced to $120 million effective September 28, 2012. With outstanding borrowings of $102.9 million and $1.4 million in letters of credit, our availability
under the credit facility at September 30, 2012, was $15.7 million.
We are currently in discussions with our lenders
regarding a borrowing base redetermination of the facility, originally scheduled to be effective on October 31, 2012, based on our oil and gas reserves at June 30, 2012. We expect the borrowing base to be reduced $22 million to $98 million effective
as of November 9, 2012. On November 5, 2012, we monetized our natural gas hedges held for delivery between July 2013 and December 2013 for $14.8 million. The proceeds from monetizing the hedges were utilized to repay outstanding borrowings
under the facility. At November 7, 2012, subsequent to the repayment, we had cash on hand of $290,000, borrowings of $86.4 million and $1.4 million in outstanding letters of credit. At that date and after giving effect to the expected borrowing base
redetermination, we had $10.2 million available under our borrowing base credit facility and $10.5 million of available liquidity. We currently believe that cash flows from our current operations and cash on hand, together with availability under
our credit facility, will be sufficient to cover our financial obligations and capital spending for the remainder of 2012. However, we may reduce our capital spending budget in the event that our operating results do not meet our current
expectations, such as if commodity prices decline further from current levels. Our capital spending will also depend on the initial drilling results from our planned oil recompletes and new oil wells. We recently selected a bank to lead a new
borrowing base facility to refinance the existing facility. Given current gas prices, we do not anticipate having meaningful liquidity for some time unless we complete the refinancing.
We have an effective $100 million universal shelf registration statement on Form S-3. We are initially limited to selling debt or equity
securities under the shelf registration statement in one or more offerings over a 12 consecutive month period for a total initial public offering price not exceeding one third of our public equity float. The registration statement is intended to
give us the flexibility to sell securities if and when market conditions and circumstances warrant, to provide funding for growth or other strategic initiatives, for debt reduction or refinancing and for other general corporate purposes. The actual
amount and type of securities or combination of securities and the terms of those securities will be determined at the time of sale, if such sale occurs. If and when a particular series of securities is offered, the prospectus supplement relating to
that offering will set forth our intended use of the net proceeds. In addition, we have entered into an at-the-market issuance sales agreement with a sales agent relating to the offering from time to time of shares of our common stock under the
shelf registration statement. Sales of shares of our common stock, if any, may be made directly on the NASDAQ Global Market, on any other existing trading market for the common stock or through a market maker, or in privately negotiated
transactions, subject to our approval. Our sales agreement is limited to the sale of up to a number of shares of common stock with an initial offering price not to exceed the amount that can be sold under the registration statement. As of the date
of the sales agreement, such amount is limited to approximately $20.3 million. We commenced sales of our common stock under the shelf registration statement in June 2012 and through October 2012, have sold 90,927 common shares for gross proceeds of
$191,000 and paid aggregate commission of $6,000 to the sales agent.
7
Escrowed proceeds from the Appalachia Basin Sale
In December 2010, we entered into an agreement with Magnum Hunter Resources Corporation (“MHR”) to sell to MHR certain oil and
gas properties and related assets in West Virginia. The sale closed in three phases for a total of $44.6 million. Of the total proceeds received from all three phases of the sale, $6.4 million was set aside in escrow to cover potential claims for
indemnity and title defects. In June 2012, $5.7 million of escrowed funds relating to the first and second closing were released after net claims of $219,000 were paid. Of the $5.7 million released, $1.3 million was retained by us while $4.4 million
was paid to the Royal Bank of Canada (“RBC”) under the previously disclosed asset sale agreement. At September 30, 2012, the remaining balance in escrow was $564,000. The balance is related to the third closing and, subject to certain
contingencies, is scheduled to be released in December 2012. If the entire remaining amount in escrow is released, we would retain $164,000 while $400,000 will be paid to a third-party.
During 2011, we settled a credit facility with RBC (the “QER Loan”) under terms that met accounting criteria to be classified
as a troubled debt restructuring. The settlement included $34.7 million in payments utilizing proceeds from the Appalachia Basin asset sale and an equity payment of $843,000. By evaluating the maximum sum of future cash flows that could be paid to
RBC, we previously recorded gains on debt restructuring of $2.9 million and $1.6 million in 2010 and 2011, respectively. Upon the final payment of $4.4 million to RBC out of the escrowed proceeds, an additional gain on debt restructuring of $255,000
was recorded in June 2012. The $1.3 million of escrowed funds retained by us included recovery of the $843,000 equity payment to RBC made in 2011.
Dilution
At September 30, 2012, including 5,257,156 shares of
our common stock held by White Deer, we had 15,562,177 shares of common stock issued and outstanding. In addition, we have 28,509,151 outstanding warrants to purchase our common stock of which 28,059,936 are owned by White Deer at an average
exercise price of $2.93 and 449,215 are owned by Constellation Energy Group Inc. at an average exercise price of $7.32. We also have 187,454 restricted stock units and 1,171,005 options outstanding granted under our long-term incentive plan.
Consequently, if these securities were included as outstanding, our outstanding shares would have been 45,429,787 of which the warrants and common stock owned by White Deer represent approximately 73%. By exercising their warrants, White Deer can
benefit from their respective percentage of all of our profits and growth. In addition, if White Deer begins to sell significant amounts of our common stock, or if public markets perceive that they may sell significant amounts of our common stock,
the market price of our common stock may be significantly impacted.
Contractual Obligations
We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases and
purchase obligations. During the first nine months of 2012, we entered into new contractual commitments for office equipment, data storage services and compressors used in our gathering system. As a result, the $3.4 million minimum amount of these
contracts over a span of five years would be an increase to the amount included in the outstanding contractual commitments table at December 31, 2011.
Other than the contractual commitments discussed above and debt repayments during the nine months ended September 30, 2012, there were no material changes to our contractual commitments since
December 31, 2011.
8
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 the Private Securities Litigation Reform Act of 1995. These statements include those regarding projections and estimates concerning the timing and success of specific projects; financial position; business strategy; budgets; amount,
nature and timing of capital expenditures; drilling of wells and construction of pipeline infrastructure; acquisition and development of oil and natural gas properties and related pipeline infrastructure; timing and amount of future production of
oil and natural gas; operating costs and other expenses; estimated future net revenues from oil and natural gas reserves and the present value thereof; cash flow and anticipated liquidity; funding of our capital expenditures; ability to meet our
debt service obligations; and other plans and objectives for future operations.
When we use the words “believe,”
“intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other
similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The factors impacting these risks and
uncertainties include, but are not limited to:
|
|
•
|
|
current weak economic conditions;
|
|
|
•
|
|
volatility of oil and natural gas prices;
|
|
|
•
|
|
increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;
|
|
|
•
|
|
access to capital, including debt and equity markets;
|
|
|
•
|
|
results of our hedging activities;
|
|
|
•
|
|
drilling, operational and environmental risks; and
|
|
|
•
|
|
regulatory changes and litigation risks.
|
You should consider carefully the statements under Item 1A. Risk Factors included in our annual report on Form 10-K for the year ended December 31, 2011, which describe factors that could cause
our actual results to differ from those set forth in the forward-looking statements. Our annual report on Form 10-K for the year ended December 31, 2011, is available on our website at
www.pstr.com
.
We have based these forward-looking statements on our current expectations and assumptions about future events. The forward-looking
statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. Readers are urged to carefully review and
consider the various disclosures made by us in our reports filed with the SEC, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more
of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.
9
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK.
The following table summarizes the estimated volumes, fixed prices and fair value attributable to oil
and gas derivative contracts at September 30, 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remainder
of
2012
|
|
|
Year Ending December 31,
|
|
|
Total
|
|
|
|
|
|
2013
|
|
|
2014
|
|
|
2015-2016
|
|
|
|
|
|
($ in thousands, except per unit data)
|
|
|
Natural Gas Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
2,762,296
|
|
|
|
9,000,003
|
|
|
|
—
|
|
|
|
1,047,000
|
|
|
|
12,809,299
|
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
7.21
|
|
|
$
|
7.28
|
|
|
$
|
—
|
|
|
$
|
4.00
|
|
|
$
|
7.00
|
|
|
Fair value, net
|
|
$
|
10,868
|
|
|
$
|
30,849
|
|
|
$
|
—
|
|
|
$
|
(710
|
)
|
|
$
|
41,007
|
|
|
Natural Gas Basis Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Mmbtu)
|
|
|
2,262,295
|
|
|
|
9,000,003
|
|
|
|
—
|
|
|
|
—
|
|
|
|
11,262,298
|
|
|
Weighted-average fixed price per Mmbtu
|
|
$
|
(0.71
|
)
|
|
$
|
(0.71
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.71
|
)
|
|
Fair value, net
|
|
$
|
(1,097
|
)
|
|
$
|
(4,563
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(5,660
|
)
|
|
Crude Oil Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract volumes (Bbl)
|
|
|
16,671
|
|
|
|
65,892
|
|
|
|
61,680
|
|
|
|
112,056
|
|
|
|
256,299
|
|
|
Weighted-average fixed price per Bbl
|
|
$
|
93.86
|
|
|
$
|
101.70
|
|
|
$
|
97.00
|
|
|
$
|
92.29
|
|
|
$
|
95.95
|
|
|
Fair value, net
|
|
$
|
19
|
|
|
$
|
525
|
|
|
$
|
335
|
|
|
$
|
423
|
|
|
$
|
1,302
|
|
|
Total fair value, net
|
|
$
|
9,790
|
|
|
$
|
26,811
|
|
|
$
|
335
|
|
|
$
|
(287
|
)
|
|
$
|
36,649
|
|
In April 2012, we repriced the portion of our natural gas swap contracts expected to settle in June, July
and August of 2012 to market prices and received proceeds of $10.8 million. In May 2012, we settled the repriced June 2012 contract by entering into new contracts in 2016. The settlement transaction resulted in a realized loss on derivative
instruments of $476,000. On November 5, 2012, we settled our natural gas swap contracts held for delivery between July 2013 and December 2013 for $14.8 million. Proceeds from the settlement were utilized to repay debt.
ITEM 4.
CONTROLS AND PROCEDURES
Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are designed to
ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and that such information is accumulated
and communicated to management, including the principal executive officer and the principal financial officer, to allow timely decisions regarding required disclosures. There are inherent limitations to the effectiveness of any system of disclosure
controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving
their control objectives.
In connection with the preparation of this quarterly report on Form 10-Q, our management, under the
supervision and with the participation of our principal executive officer and principal financial officer, conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30,
2012. Based on that evaluation, our principal executive officer and principal financial officer concluded that, as of September 30, 2012, our disclosure controls and procedures were effective with respect to the recording, processing,
summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.
There were no changes in internal control over financial reporting that occurred during the quarter covered by this report that have
materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
10
PART II — OTHER INFORMATION
ITEM 1.
LEGAL PROCEEDINGS.
See Note 11 in Part I, Item 1 of this Quarterly Report entitled “Commitments and Contingencies,” which is incorporated
herein by reference.
ITEM 1A.
RISK FACTORS.
For additional information about our risk factors, see Item 1A. “Risk Factors” in our 2011 10-K.
11
ITEM 6.
EXHIBITS
|
|
|
|
|
|
|
|
2.1
|
|
Purchase Agreement, dated September 28, 2012, among PostRock Energy Corporation, PostRock Energy Services Corporation, PostRock KPC Pipeline, LLC and MV Pipelines, LLC (incorporated
herein by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on October 3, 2012).
|
|
|
|
|
4.1
|
|
Amended and Restated Certificate of Designations for the Series A Cumulative Redeemable Preferred Stock (incorporated herein by reference to Exhibit 4.1 to the Current Report on
Form 8-K filed on August 7, 2012).
|
|
|
|
|
4.2
|
|
Form of Warrant with respect to the White Deer SPA (as defined below) (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on August 7,
2012).
|
|
|
|
|
10.1
|
|
Second Amendment to Second Amended and Restated Credit Agreement, dated as of July 20, 2012, among PostRock Energy Services Corporation and PostRock MidContinent Production,
LLC, as Borrowers, Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2012,
filed on August 8, 2012).
|
|
|
|
|
10.2
|
|
Securities Purchase Agreement, dated August 1, 2012, (“White Deer SPA”) among PostRock Energy Corporation, White Deer Energy L.P., White Deer Energy TE L.P. and White Deer
Energy FI L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 7, 2012).
|
|
|
|
|
10.3
|
|
Amendment No. 2, dated as of August 1, 2012, among PostRock Energy Corporation, White Deer Energy L.P., White Deer Energy TE L.P. and White Deer Energy FI L.P., to the First Amended
and Restated Registration and Investor Rights Agreement, dated August 8, 2011, by and among PostRock Energy Corporation, Constellation Energy Commodities Group, Inc., White Deer Energy L.P., White Deer Energy TE, L.P. and White Deer Energy FI L.P.
(incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on August 7, 2012).
|
|
|
|
|
31.1*
|
|
Certification by principal executive officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
|
|
31.2*
|
|
Certification by principal financial officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
|
|
32.1*
|
|
Certification by principal 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 principal financial officer pursuant to 18 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 Labels Linkbase Document.
|
|
|
|
|
101.PRE**
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
|
|
|
|
101.DEF**
|
|
Taxonomy Extension Definition Linkbase Document.
|
|
†
|
Management contracts and compensatory plans and arrangements.
|
12
PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed
or incorporated by reference the agreements referenced above as exhibits to this Quarterly Report on Form 10-Q. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to
provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect
to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules no included with the exhibits. These disclosure schedules may contain information that modifies,
qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk
between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent
information may or may not be fully reflected in the Company’s public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about
the Company or its business or operations on the date hereof.
13
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 this 7th day of November 2012.
|
|
|
|
|
PostRock Energy Corporation
|
|
|
|
|
By:
|
|
/s/ Terry W. Carter
|
|
|
|
Terry W. Carter
|
|
|
|
Chief Executive Officer and President
|
|
|
|
|
By:
|
|
/s/ David. J. Klvac
|
|
|
|
David J. Klvac
|
|
|
|
Executive Vice President, Chief Financial Officer and Chief Accounting Officer
|
14
Grafico Azioni PostRock Energy (CE) (USOTC:PSTRQ)
Storico
Da Giu 2024 a Lug 2024
Grafico Azioni PostRock Energy (CE) (USOTC:PSTRQ)
Storico
Da Lug 2023 a Lug 2024
