NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Constellation Energy Partners LLC (CEP, we, us, our or the Company) was organized as a limited liability company on February 7, 2005, under the laws of the State of Delaware. We completed our initial public offering on November 20, 2006, and currently trade on the NYSE MKT LLC (NYSE MKT) under the symbol “CEP”. Through subsidiaries, PostRock Energy Corporation (NASDAQ: PSTR) (PostRock), Exelon Corporation (NYSE: EXC) (Exelon) and Sanchez Oil & Gas Corporation (SOG) own a portion of our outstanding units. As of
March
3
1
, 201
4
, Constellation Energy Partners Management, LLC (CEPM), a subsidiary of PostRock, owned
484,505
, or
30
%,
of our Class A units and
5,918,894
of our Class B common units. Constellation Energy Partners Holdings, LLC (CEPH), a subsidiary of Exelon, owned all of our Class C management incentive interests and all of our Class D interests. Sanchez Energy Partners I, LP (SEP I), a subsidiary of SOG, owned
1,130,512
, or
70
%, of our Class A units and
4,724,407
of our Class B common units.
We are currently focused on the
acquisition,
development and
production
of oil and natural gas properties
, as well as midstream assets. Our proved reserves are located
in the Cherokee Basin in Oklahoma
and Kansas
, the Woodford Shale
in the Arkoma Basin
in Oklahoma, the Central Kansas Uplift in Kansas and in Texas and Louisiana.
Basis of Presentation
These unaudited condensed consolidated financial statements include the accounts of CEP and our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. We operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties.
These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (SEC). Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP), have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP.
These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of CEP and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2013, which was filed with the SEC on March 27, 2014.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (NGLs); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Reclassifications
Certain reclassifications have been made to the prior period to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.
Discontinued Operations
In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin in Alabama. The related results of operations and cash flows have been classified as discontinued operations in the condensed consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information for the three months ended March 31, 2013. Unless otherwise indicated, information presented in the Notes to Condensed Consolidated Financial Statements relates only to the Company’s continuing operations. Information related to discontinued operations is included in Note 3.
Acquisition and Divestiture.
New Accounting Pronouncements
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption.
In December 2011, the FASB issued Accounting Standards Updates (ASU) No. 2011-11,
Disclosures about Offsetting Assets and Liabilities
, which requires additional disclosures for financial and derivative instruments that are either (1) offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, regardless of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The guidance was effective beginning on or after January 1, 2013, and primarily impacts the disclosures associated with our commodity and interest rate derivatives. Implementation of this guidance did not have any material impact on our consolidated financial position, results of operations or cash flows.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2013.
Earnings per Unit
Basic earnings per unit (EPU) is computed by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) is allocated
to each class with the Class A units receiving 2% and the Class B units receiving 98%
.
As of
March
31, 201
4
and 201
3
, we had unvested restricted common units outstanding, which were considered dilutive securities. These units will be considered in the diluted weighted average common units outstanding number in periods of net income. In periods of net losses, these units are excluded for the diluted weighted average common unit outstanding number as they are not participating securities.
The following table presents our calculation of basic and diluted units outstanding for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2014
|
|
2013
|
Weighted average units outstanding during period:
|
|
|
|
|
|
|
Class A units - Basic and Diluted
|
|
|
1,615,017
|
|
|
484,396
|
Class B Common units - Basic and Diluted
|
|
|
28,214,104
|
|
|
23,766,266
|
|
|
|
29,829,121
|
|
|
24,250,662
|
At
March
31, 201
4
, we had
129,537
Class B common units that were restricted unvested common units granted and outstanding. These units were excluded from the diluted weighted average common unit outstanding number.
The following table presents our basic and diluted
loss
per unit for the
three months
ended
March
31, 201
4
(in thousands, except for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
Class A Units
|
|
Class B Units
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
$
|
(2,939)
|
|
|
|
|
|
|
Distributions
|
|
|
-
|
|
$
|
-
|
|
$
|
-
|
Assumed net loss to be allocated
|
|
$
|
(2,939)
|
|
$
|
(59)
|
|
$
|
(2,880)
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted loss per unit
|
|
|
|
|
$
|
(0.04)
|
|
$
|
(0.10)
|
The following table presents our basic and diluted
loss
per unit for the
three months
ended
March
31, 201
3
(in thousands, except for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
Class A Units
|
|
Class B Units
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations
|
|
$
|
(10,646)
|
|
|
|
|
|
|
Distributions
|
|
|
-
|
|
$
|
-
|
|
$
|
-
|
Assumed allocation of loss from continuing operations
|
|
|
(10,646)
|
|
|
(213)
|
|
|
(10,433)
|
Discontinued operations
|
|
|
(2,686)
|
|
|
(54)
|
|
|
(2,632)
|
Assumed net loss to be allocated
|
|
$
|
(13,332)
|
|
$
|
(267)
|
|
$
|
(13,065)
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted loss from continuing operations per unit
|
|
|
|
|
$
|
(0.44)
|
|
$
|
(0.44)
|
Basic and diluted loss from discontinued operations per unit
|
|
|
|
|
$
|
(0.11)
|
|
$
|
(0.11)
|
Basic and diluted loss per unit
|
|
|
|
|
$
|
(0.55)
|
|
$
|
(0.55)
|
Cash
All highly liquid investments with original maturities of three months or less are considered cash. Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on. There were no checks-in-transit reported in accounts payable at
March 31, 2014 and
December 31, 2013.
Restricted C
ash
Restricted cash
,
at March 31, 2014 and December 31, 2013, of $1.7 million
wa
s being held in escrow. Of this balance, $0.6 million is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved. The remaining amount of $1.1 million is related to the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama. These funds will remain in escrow for a period ending February 28, 2015, pending certain
post-
closing conditions.
The restricted cash was classified as a non-current asset at December 31, 2013, but was reclassified to a current asset at March 31, 2014, based on the conditions of the cash held in the account.
Accounts Receivable, Net
Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. At March 31, 2014 and 2013, we had an allowance for doubtful accounts receivable of $0.2 million and $0.1 million, respectively.
3. ACQUISITION AND DIVESTITURE
Sale of Robinson’s Bend Field Assets
On February 28, 2013, we sold
all of
our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $
63.0
million, subject to closing adjustments
that amounted to approximately $
4.0
million
. We recorded a loss on the sale of approximately $
3.1
million in the three months ended March 31, 2013.
The sale of the Robinson’s Bend Field assets was initiated to provide the financial flexibility necessary to support our efforts for pursuing opportunities and further developing our properties in the Mid-Continent region, as well as reducing our outstanding debt.
The following amounts relating to the Robinson’s Bend Field assets have been reported as discontinued operations in the condensed consolidated statements of operat
ions for the three months ended
March 31, 2013 (in thousands):
|
|
|
|
|
|
|
Three Months Ended
|
|
March 31, 2013
|
Revenues
|
$
|
2,304
|
Loss from discontinued operations
|
$
|
(2,686)
|
See Note
2 for information regarding earnings per unit, including earnings per unit data relating to
loss
from discontinued operations.
The condensed consolidated statements of cash flows reflect discontinued operations for the three months ended March 31, 2013.
Acquisition
of
Oil
, Natural Gas
and
Natural
Gas
Liquids
Properties
f
rom SEP I
On August 9, 2013, we acquired oil, natural gas and
NGLs
assets in Texas and Louisiana from SEP I for a purchase price of $
30.4
million. In conjunction with the acquisition, SEP I received $
20.1
million in cash;
1,130,512
Class A units, which
represented
70.0
% of the total Class A units
outstanding as of such date,
and
4,724,407
Class B units, which represented
16.6
% of the tot
al Class B
units outstanding as of such date
. The cash portion of the transaction was financed with cash on hand and a borrowing of $
16.7
million under our reserve-based credit facility.
The acquired assets include
67
producing
wells in Texas and Louisiana. The primary factors considered by management in acquiring the
S
EP
I
properties include the belief that these wells provide an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus of increasing our oil-weighted assets. The
SEP I
properties also provide us with access to exploitation and development potential.
The following allocation of the purchase price is preliminary and includes estimates. This preliminary allocation is based on information that was available to management at the time these condensed consolidated financial statements were prepared and takes into account current market conditions and estimated market prices for oil and natural gas.
The following table summarizes the estimated values of assets acq
uired
and liabilities assumed
effective August 1, 2013 (in thousands)
:
|
|
|
|
|
|
|
|
|
|
August 1, 2013
|
Oil and natural gas properties, equipment and facilities
|
|
$
|
31,497
|
Asset retirement obligation
|
|
|
(1,088)
|
Net assets acquired
|
|
$
|
30,409
|
We have accounted for our acquisition of oil and natural gas properties using the purchase method of accounting for business combinations, and therefore we have estimated the fair value of the assets acquired and the liabilities assumed as of the acquisition date. The fair value
measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and there
fore
represent Level 3 inputs. The fair value of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that
convert
future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii)
future commodity prices, (iv) estimated future cash flows and (v) a market-based weighted cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
Pro Forma Information
The following supplemental pro forma information presents consolidated results of operations as if the acquisition of the
SEP I
properties had occurred on January 1, 201
3
. The supplemental unaudited pro forma information was derived from a) our historical consolidated statements of operations and b) the statements of operations of SEP I. This information does not purport to be indicative of results of operations that would have occurred had the acquisition occurred on January 1, 201
3
, nor is such information indicative of any expected future results of operations.
|
|
|
|
|
|
|
Pro Forma
|
|
Three Months Ended
|
(In thousands)
|
March 31, 2013
|
Revenue
|
$
|
9,648
|
Loss from continuing operations
|
$
|
(7,729)
|
Discontinued operations
|
$
|
(2,686)
|
Net Loss
|
$
|
(10,415)
|
Loss from continuing operations per unit
|
Class A units - Basic and diluted
|
$
|
(0.10)
|
Class B units - Basic and diluted
|
$
|
(0.27)
|
Discontinued operations per unit
|
|
|
Class A units - Basic and diluted
|
$
|
(0.03)
|
Class B units - Basic and diluted
|
$
|
(0.09)
|
Net loss per unit
|
|
|
Class A units - Basic and diluted
|
$
|
(0.13)
|
Class B units - Basic and diluted
|
$
|
(0.36)
|
Weighted average units outstanding
|
|
|
Class A units - Basic and diluted
|
|
1,614,908
|
Class B units - Basic and diluted
|
|
28,490,673
|
4. FAIR VALUE MEASUREMENTS
We measure certain financial assets and liabilities at fair value. Fair value is defined as an “exit price” which represents the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in valuing an asset or liability. The accounting guidance also requires the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize the use of unobservable inputs. As a basis for considering such assumptions and inputs, a fair value hierarchy has been established which identifies and prioritizes three levels of inputs to be used in measuring fair value.
The three levels of the fair value hierarchy are as follows:
Level 1 – Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2 – Inputs other than the quoted prices in active markets that are observable either directly or indirectly, including: quoted prices for similar assets and liabilities in active markets; quoted prices for identical or similar assets and liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data.
Level 3 – Unobservable inputs that are supported by little or no market data and require the reporting entity to develop its own assumptions.
As required by accounting guidance for fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at March 31, 2014
|
|
Quoted Prices in
|
|
Significant other
|
|
|
|
|
|
|
|
|
|
|
Active Markets for
|
|
Observable
|
|
Significant
|
|
|
|
|
|
|
|
Identical Assets
|
|
Inputs
|
|
Unobservable Inputs
|
|
Netting Cash and
|
|
Fair Value at
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Collateral
|
|
March 31, 2014
|
Risk Management Assets
|
$
|
-
|
|
$
|
7,144
|
|
$
|
-
|
|
$
|
(1,539)
|
|
$
|
5,605
|
Risk Management Liabilities
|
|
-
|
|
|
(1,539)
|
|
|
-
|
|
|
1,539
|
|
|
-
|
Total Net Assets and Liabilities
|
$
|
-
|
|
$
|
5,605
|
|
$
|
-
|
|
$
|
-
|
|
$
|
5,605
|
The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2013
|
|
Quoted Prices in
|
|
Significant other
|
|
|
|
|
|
|
|
|
|
|
Active Markets for
|
|
Observable
|
|
Significant
|
|
|
|
|
|
|
|
Identical Assets
|
|
Inputs
|
|
Unobservable Inputs
|
|
Netting Cash and
|
|
Fair Value at
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Collateral
|
|
December 31, 2013
|
Risk Management Assets
|
$
|
-
|
|
$
|
11,577
|
|
$
|
-
|
|
$
|
(975)
|
|
$
|
10,602
|
Risk Management Liabilities
|
|
-
|
|
|
(975)
|
|
|
-
|
|
|
975
|
|
|
-
|
Total Net Assets and Liabilities
|
$
|
-
|
|
$
|
10,602
|
|
$
|
-
|
|
$
|
-
|
|
$
|
10,602
|
As of March 31, 2014, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature.
Fair Value of Financial Instruments
Fair value guidance requires certain fair value disclosures, such as those on our debt and derivatives, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.
Reserve-Based Credit Facility
– We believe that the carrying value of long-term debt for our reserve-based credit facility approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms. The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties. Our reserve-based credit facility is discussed further in Note 7.
Derivative Instruments
– The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate. Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value.
5. DERIVATIVE AND FINANCIAL INSTRUMENTS
To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These transactions are normally price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never our intention to enter into derivative contracts for speculative trading purposes.
Under ASC Topic 815,
Derivatives and Hedging
, all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accou
nting criteria are met. We have not
elected to designate
any
of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the condensed consolidated statements of operations.
As of March 31, 2014, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:
MTM Fixed Price Swaps—NYMEX (Henry Hub)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the quarter ended (in MMBtu)
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Total
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
2014
|
|
|
|
|
|
1,592,500
|
|
$
|
5.75
|
|
1,610,000
|
|
$
|
5.75
|
|
1,610,000
|
|
$
|
5.75
|
|
4,812,500
|
|
$
|
5.75
|
2015
|
1,215,420
|
|
$
|
4.25
|
|
1,153,487
|
|
$
|
4.25
|
|
1,096,023
|
|
$
|
4.26
|
|
1,050,219
|
|
$
|
4.26
|
|
4,515,149
|
|
$
|
4.25
|
2016
|
1,010,633
|
|
$
|
4.21
|
|
967,290
|
|
$
|
4.21
|
|
923,541
|
|
$
|
4.21
|
|
893,568
|
|
$
|
4.22
|
|
3,795,032
|
|
$
|
4.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,122,681
|
|
|
|
MTM Fixed Price Basis Swaps– Enable Gas Transmission, LLC (East), ONEOK Gas Transportation (Oklahoma), or Southern Star Central Gas Pipeline (Texas, Oklahoma, and Kansas)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the quarter ended (in MMBtu)
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Total
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
Volume
|
|
Average $
|
|
Volume
|
|
Average $
|
|
Volume
|
|
Average $
|
|
Volume
|
|
Average $
|
|
Volume
|
|
Average $
|
2014
|
|
|
|
|
|
1,133,022
|
|
$
|
0.39
|
|
1,084,270
|
|
$
|
0.39
|
|
1,047,963
|
|
$
|
0.39
|
|
3,265,255
|
|
$
|
0.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,265,255
|
|
|
|
MTM Fixed Price Basis Swaps–West Texas Intermediate (WTI)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the quarter ended (in Bbls)
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Total
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
|
|
Average
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
|
Volume
|
|
Price
|
2014
|
|
|
|
|
|
57,154
|
|
$
|
94.67
|
|
53,797
|
|
$
|
94.72
|
|
50,597
|
|
$
|
94.80
|
|
161,548
|
|
$
|
94.73
|
2015
|
47,747
|
|
$
|
90.95
|
|
45,065
|
|
$
|
91.00
|
|
42,672
|
|
$
|
91.04
|
|
40,329
|
|
$
|
91.10
|
|
175,813
|
|
$
|
91.02
|
2016
|
17,957
|
|
$
|
85.50
|
|
16,985
|
|
$
|
85.50
|
|
16,048
|
|
$
|
85.50
|
|
15,127
|
|
$
|
85.50
|
|
66,117
|
|
$
|
85.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
403,478
|
|
|
|
The table below outlines the classification of our derivative financial instruments on the condensed consolidated balance sheet (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Asset/(Liability)
|
|
|
Location of Asset/(Liability)
|
|
On Balance Sheet
|
Derivative Type
|
|
On Balance Sheet
|
|
March 31, 2014
|
|
December 31, 2013
|
|
|
|
|
|
|
|
|
|
Commodity – MTM
|
|
Risk management assets - current
|
|
$
|
5,837
|
|
$
|
10,043
|
Commodity – MTM
|
|
Risk management assets - non-current
|
|
|
1,308
|
|
|
1,534
|
|
|
Total gross assets
|
|
|
7,145
|
|
|
11,577
|
|
|
|
|
|
|
|
|
|
Commodity – MTM
|
|
Risk management assets – current
|
|
|
(1,393)
|
|
|
(902)
|
Commodity – MTM
|
|
Risk management assets – non-current
|
|
|
(147)
|
|
|
(73)
|
|
|
Total gross liabilities
|
|
|
(1,540)
|
|
|
(975)
|
|
|
Total net assets and liabilities
|
|
$
|
5,605
|
|
$
|
10,602
|
The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain/(Loss) in Income
|
|
|
Location of Gain/(Loss)
|
|
For the Three Months Ended March 31,
|
Derivative Type
|
|
in Income
|
|
2014
|
|
2013
|
|
|
|
|
|
|
|
|
|
Commodity – Mark-to-Market
|
|
Oil and natural gas sales
|
|
$
|
(4,074)
|
|
$
|
(4,580)
|
Interest Rate – Mark-to-Market
|
|
Interest expense
|
|
|
-
|
|
|
(45)
|
|
|
Total
|
|
$
|
(4,074)
|
|
$
|
(4,625)
|
There were no gains or losses reclassified from accumulated other comprehensive income into income during the three months ended March 31, 2014 or 2013.
Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with
two
counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election.
We monitor the creditworthiness of our counterparties; however, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, if such changes are sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our counterparties not perform, we may not realize the benefit of some of our derivative instruments with lower commodity prices and may incur losses. We include a measure of counterparty credit risk in our estimates of the fair values of the derivative instruments in an asset position.
We currently use our reserve-based credit facility to provide credit support for our derivative transactions. As a result, we do not post cash collateral with our counterparties, and have minimal non-performance credit risk on our liabilities with our counterparties. We utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our net assets from counterparties. At March 31, 2014 and
December
31, 2013, the impact of non-performance credit risk on the valuation of our net assets from counterparties was not significant, and
the entire amount was reflected as a decrease to our non-cash mark-to-market gain
, respectively
.
We entered into new swap agreements to hedge
an additional
portion of our future oil production on April 29, 2014. See Note 14 for further discussion.
Hedge Liquidation
and
Repositioning
In the first quarter of 2013, we liquidated or repositioned certain of our hedges. In connection with the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama, we liquidated
395,218
MMbtu of NYMEX swaps in 2013 and
1,634,530
MMbtu of NYMEX swaps in 2014 at a cost of $
0.3
million. In addition, we reduced our outstanding NYMEX swap positions in 2013 by
1,041,814
MMbtu by executing offsetting trades with one of our counterparties at a fixed price of $
3.66
per Mcf
. These transactions ensure that our outstanding derivative positions in future periods are lower than our expected future natural gas production in those periods. We also amended a 2014 to 2015 oil trade with one of our hedge counterparties to lower the stated swap price from $
98.10
to $
93.50
per barrel
, on a total of
58,157
barrels of oil. We received proceeds of approximately $
0.2
million upon execution of the amendment. The proceeds were used for working capital purposes.
In March 2013, we reduced our outstanding interest rate swaps that fix our LIBOR rate through 2014 to $30 million, which increased our interest rate swap settlements by $2.1 million. This position was terminated in May 2013 resulting in an offsetting non-cash gain in our mark-to-market interest swap activities.
6. OIL AND NATURAL GAS PROPERTIES
Oil and natural gas properties consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2014
|
|
December 31, 2013
|
Oil and natural gas properties and related equipment
|
|
|
|
|
|
(successful efforts method)
|
|
|
|
|
|
Property (acreage) costs
|
|
|
|
|
|
Proved property
|
$
|
639,141
|
|
$
|
636,816
|
Unproved property
|
|
1,648
|
|
|
1,589
|
Total property costs
|
|
640,789
|
|
|
638,405
|
Materials and supplies
|
|
1,057
|
|
|
1,054
|
Land
|
|
751
|
|
|
751
|
Total
|
|
642,597
|
|
|
640,210
|
Less: Accumulated depreciation, depletion, amortization and impairments
|
|
(499,321)
|
|
|
(495,215)
|
Oil and natural gas properties and equipment, net
|
$
|
143,276
|
|
$
|
144,995
|
Depreciation, depletion, amortization and impairments consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2014
|
|
2013
|
|
|
|
|
|
|
DD&A of oil and natural gas-related assets
|
$
|
4,050
|
|
$
|
4,798
|
Asset Impairments
|
|
149
|
|
|
-
|
Total
|
$
|
4,199
|
|
$
|
4,798
|
Impairment of Oil and Natural Gas Properties and Other Non-Current Assets
For the three months ended March 31, 2014, o
ur non-cash impairment charges were approximately $
0.1
million to impair the value of our oil and natural g
as fields in Texas and Louisiana,
and for
the three months ended
March 31, 2013, we did not have an impairment to record.
The impairment was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report.
Asset Sales
During
each of the three-month periods
ended March 31, 2014 and March 31, 2013, we sold miscellaneous surplus equipment for less than $
0.1
million resulting in an immaterial gain on the asset sale
s
.
Useful Lives
Our furniture, fixtures and equipment are depreciated over a life of
one
to
seven
years, buildings are depreciated over a life of
20
years and pipeline and gathering systems are depreciated over a life of
25
to
40
years.
Exploration and Dry Hole Costs
We recorded
no
exploration and dry hole costs for the three months ended March 31, 2014 and 2013, respectively. These costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs and the impairment, amortization and abandonment associated with leases on our unproved properties.
7. DEBT
Reserve-Based Credit Facility
In May 2013, we
refinanced our
$350.0
million reserve-based credit facility with Societe Generale as administrative and collateral agent and a syndicate of lenders, extending its maturity to
May 30, 2017
and increasing our borrowing base from $
37.5
million to $
55.0
million. On May 6, 2014, our borrowing base under the reserve-based credit facility was increased to $
70.0
million. Borrowings under the reserve-based credit facility are secured by various mortgages of oil and natural gas properties that we and certain of our subsidiaries own, as well as various security and pledge agreements among us and certain of our subsidiaries and the administrative agent. The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties. As of March 31, 2014, we had borrowed $
50.7
million under our reserve-based credit facility and our borrowing base was $
55.0
million. At March 31, 2014, the lenders and their percentage commitments in the reserve-based credit facility were Societe Generale (
36.36
%), OneWest Bank, FSB (
36.36
%) and BOKF NA, dba Bank of Oklahoma (
27.28
%).
Borrowings under the reserve-based credit facility are available for acquisition, exploration, operation and maintenance of oil and natural gas properties, payment of expenses incurred in connection with the reserve-based credit facility, working capital and general limited liability company purposes. The reserve-based credit facility has a sub-limit of
$20.0
million which may be used for the issuance of letters of credit. As of March 31, 2014,
no
letters of credit were outstanding.
At our election, interest for borrowings
is
determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin between
2.50
% and
3.50
% per annum based on utilization
or (ii) a domestic bank rate (
ABR) plus an applicable margin between
1.50
% and
2.50
% per annum based on utilization plus (iii) a commitment fee of
0.50
% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.
The reserve-based credit facility contains various covenants that limit, among other things, our ability and certain of our subsidiaries’ ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets
and
make certain loans, acquisitions, capital expenditures and investments. The reserve-based credit facility limits our ability to pay distributions to unitholders and permits us to hedge our projected monthly production
, as discussed below,
and the interest rate on our borrowings.
In addition, we are required to maintain (i) a ratio of Total Net Debt (defined as Debt (generally indebtedness permitted to be incurred by us under the reserve-based credit facility) less Available Cash (generally, cash, cash equivalents and cash reserves of the Company)) to Adjusted EBITDA (generally, for any period, the sum of consolidated net income for such period plus (minus) the following expenses or charges to the extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization, write-off of deferred financing fees, impairment of long-lived assets, (gain) loss on sale of assets, exploration costs, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on derivatives and realized (gain) loss on cancelled derivatives and other similar charges) of not more than
3.5
to 1.0; (ii) Adjusted EBITDA to cash interest expense of not less than
2.5
to 1.0; and (iii) consolidated current assets, including the unused amount of the total commitments but excluding current non-cash assets, to consolidated current liabilities, excluding non-cash liabilities and current maturities of debt (to the extent such payments are not past due), of not less than
1.0
to 1.0, all calculated pursuant to the requirements under Accounting Standards Codification (ASC) Topic 815,
Derivatives and Hedging
; ASC Topic 410,
Asset Retirement and Environmental Obligations
and ASC Topic 360,
Property, Plant and Equipment
. All financial covenants are calculated using our consolidated financial information and are discussed below.
The reserve-based credit facility also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, guaranties not being valid under the reserve-based credit facility and a change of control. A change of control is generally defined as the occurrence of both of the following events: (i) wholly-owned subsidiaries of Constellation Energy Group, Inc. are the owner of
20%
or less of an interest in us (which has now occurred) and (ii) any person or group of persons acting in concert are the owner of more than
35%
of an interest in us. These events have not both occurred, so a change in control had not occurred as of March 31, 2014. If an event of default occurs, the lenders will be able to accelerate the maturity of the reserve-based credit facility and exercise other rights and remedies. The reserve-based credit facility contains a condition to borrowing and a representation that no material adverse effect (MAE) has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of us and our subsidiaries who are guarantors taken as a whole. If a MAE were to occur, we would be prohibited from borrowing under the reserve-based credit facility and would be in default, which could cause all of our existing indebtedness to become immediately due and payable.
The reserve-based credit facility limits our ability to pay distributions to unitholders. We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the reserve-based credit facility, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the reserve-based credit facility exceed
90%
of our borrowing base, after giving effect to the proposed distribution. Our available cash is reduced by any cash reserves established by our board of managers for the proper conduct of our business and the payment of fees and expenses. As of March 31, 2014, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions.
The reserve-based credit facility permits us to hedge our projected monthly production, provided that (a) for the immediately ensuing twelve-month period, the volumes of production hedged in any month may not exceed our reasonable business judgment of the production for such month consistent with the application of petroleum engineering methodologies for estimating proved developed producing reserves based on the then-current strip pricing (provided that such projection shall not be more than
115%
of the proved developed producing reserves forecast for the same period derived from the most recent reserve report of our petroleum engineers using the then strip pricing), and (b) for the period beyond twelve months, the volumes of production hedged in any month may not exceed the reasonably anticipated projected production from proved developed producing reserves estimated by our petroleum engineers. The reserve-based credit facility also permits us to hedge the interest rate on up to
90%
of the then-outstanding principal amounts of our indebtedness for borrowed money.
The reserve-based credit facility contains no covenants related to PostRock’s, Exelon’s or SOG’s ownership in us.
Compliance with Debt Covenants
At
March
3
1
, 201
4
, we were in compliance with the financial covenants contained in our reserve-based credit facility
. We monitor compliance on an on-going basis.
If we are unable to remain in compliance with the financial covenants contained in our reserve-based credit facility or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of our reserve-based credit facility, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated covenants from the lenders, but there is no assurance that such waivers would be granted.
The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties. As of March 31, 2014, our borrowing base was $55.0 million. The borrowing base is re-determined semi-annually, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas pricing prevailing at such time. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders.
Funds Available for Borrowing
As of
March
3
1
, 201
4
and 201
3
, we
had $
50.7
million and
$34.0
million
, respectively, in outstanding debt under our reserve-based credit facility. As of
March
3
1
, 201
4
, we had $
4.3
million
available
under our reserve-based credit facility.
Subsequent to March 31, 2014, we had the following activity on our reserve-based credit facility. On April 1, 2014, in connection with the PostRock litigation settlement, we borrowed $
2.5
million. On April 4, 2014, we borrowed an additional $
1.25
million in connection with the purchase of assets in LaSalle Parish, Louisiana. We repaid $
2.5
million of the borrowings on May 1, 2014. On May 6, 2014, our borrowing base under our reserve-based credit facility was increased from $55.0 million to $
70.0
million. On May 13, 2014, we borrowed an additional $2.0 million, which was repaid on May 15, 2014, resulting in a borrowing capacity of approximately $
18.0
million available under our reserve-based credit facility as of that date.
Debt Issue Costs
As of
March
3
1
, 201
4
, our unamortized debt issue costs were
approximately $
0.8
million
. These costs are being amortized over the life of our reserve-based credit facility
. At December 31, 2013, our unamortized debt issue costs were approximately $
0.8
million.
8. ASSET RETIREMENT OBLIGATION
We recognize the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (ARC) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities. Subsequently, the ARC is depreciated using a systematic and rational method over the asset’s useful life. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells, and decommissioning of oil and natural gas gathering and other facilities.
Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas property balance.
The following table is a reconciliation of the ARO (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
|
2014
|
|
2013
|
Asset retirement obligation, beginning balance
|
$
|
9,513
|
|
$
|
7,665
|
Liabilities added from acquisitions
|
|
-
|
|
|
1,088
|
Liabilities added from drilling
|
|
18
|
|
|
244
|
Settlements
|
|
-
|
|
|
(3)
|
Accretion expense
|
|
150
|
|
|
519
|
Asset retirement obligation, ending balance
|
$
|
9,681
|
|
$
|
9,513
|
Additional asset retirement obligations increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for asset retirement obligations. At
March
3
1
, 201
4
, and December 31, 201
3
, there were
no
significant expenditures for abandonments and there were
no
assets legally restricted for purposes of settling existing asset retirement obligations.
9. COMMITMENTS AND CONTINGENCIES
On August 30, 2013, a lawsuit was filed in the Chancery Court of the State of Delaware by CEPM, Gary M. Pittman and John R. Collins against the Company, certain of its officers and managers, SOG and SEP I in connection with the Company’s closing on August 9, 2013 of the purchase of oil and
natural
gas properties from SEP I and the issuance of units in connection therewith. The plaintiffs contend
ed
, among other things, that the issuance of the units to SEP I in connection with the acquisition was not permitted under the Company’s operating agreement, that Messrs. Pittman and Collins should not have been removed as the Class A managers of the Company’s board of managers, and that SEP I, SOG and our current Class A managers
participated in
bad faith conduct of the other defendants and interfered with CEPM’s contractual rights under the Company’s operating agreement. The plaintiffs allege
d
claims against the Company and certain of its managers and officers relating to breach of contract, breach of the duty of good faith, and breach of the implied covenant of good faith and fair dealing; the plaintiffs also allege
d
aiding and abetting and tortuous interference claims against SOG, SEP I and our current Class A managers. The plaintiffs s
ought
, among other things, declaratory relief reappointing Messrs. Pittman and Collins to the Company’s board of managers and removing our current Class A managers therefrom, and an injunction against the Company taking any further action outside the ordinary course of business during the pendency of the litigation, declaratory relief rescinding the units issued by the Company to SEP I, declaratory relief that CEPM ha
d
sole voting power with respect to the outstanding Class A units, declaratory relief that the Company’s officers and managers breached fiduciary and contractual duties and
we
re not entitled to indemnification from the Company as a result thereof, and monetary damages.
On March 31, 2014, the parties to the lawsuit reached a settlement agreement and the lawsuit was subsequently dismissed. As a result of the settlement, the Class A units acquired by SEP I in the August 2013 transaction will be returned to CEP and cancelled in exchange for $
0.8
million; CEPM will transfer
100
% of its Class A units to SEP I and
414,938
of CEP’s Class B units to SEP I in exchange for an aggregate payment of $
1.0
million from SEP I, and CEP will pay $
6.5
million to CEPM. In addition, pursuant to the terms of the settlement, CEPM agreed to sell its remaining Class B units over the next nine months, with SEP I providing up to a $
5.0
million backstop payment to CEPM to the extent proceeds received by CEPM from such sale do not meet or exceed a specified amount. As a result of the settlement, the settling parties filed a stipulation in the Court of Chancery of the State of Delaware seeking to lift the preliminary injunction issued on December 3, 2013, and the litigation was dismissed with prejudice. The settlement also included mutual releases between the plaintiffs and defendants. In connection with the settlement, we received $
1.25
million on April 10, 2014, under our directors and officers insurance policy.
On February 28, 2014, a lawsuit was filed in the Chancery Court of the State of Delaware by CEPH against the Company (the Exelon Litigation) seeking repayment of suspended distributions in relation to the Class D Interests held by CEPH. In 2006, Constellation Holding, Inc (CHI), which merged with and into CEPH in December 2012, purchased the Company’s Class D Interests for $
8.0
million. The $8.0 million was to be repaid to CEPH in quarterly distributions of $
333,333.33
over a period of
six
years; however, these distributions could be temporarily suspended if a dispute arose over pricing formulas related to the sale of natural gas from the Robinson’s Bend properties. A dispute arose, so the distributions were suspended pursuant to the Company’s operating agreement and never reinstated. CEPH contends, among other things, that the Company breached its contract to pay the quarterly distributions, acted in bad faith and received unjust enrichment by suspending the quarterly distributions. The Company believes that the allegations contained in the lawsuit are without merit and is vigorously defending itself against the claims raised in the complaint. In conjunction with its defense in the Exelon Litigation, the Company anticipates that it will incur legal and other costs that may have a material effect on available cash which could impact CEP’s ability to make distributions.
10. RELATED PARTY TRANSACTIONS
Unit Ownership
PostRock, Exelon and SOG, through subsidiaries, own a portion of our outstanding units. As of March 31, 2014, CEPM, a subsidiary of PostRock, owned
484,505
, or
30
%,
of our Class A units and
5,918,894
of our Class B common units. CEPH, a subsidiary of Exelon, owned all of our Class C management incentive interests and all of our Class D interests as of March 31, 2014. SEP I, a subsidiary of SOG, owned
1,130,512
, or
70
%, of our Class A units and
4,724,407
of our Class B common units as of March 31, 2014.
PostRock-Related Announcements
In 2011, PostRock acquired certain of our Class A units and Class B common units in two separate transactions which represented a
21.3
% ownership interest in us at March 31, 2014. Approval of the purchase of these units was neither required nor given by our board of managers or conflicts committee. We believe PostRock is now an “interested unitholder” under Section 203 of the Delaware General Corporation Law, which is applicable to us pursuant to our operating agreement. Section 203, as it applies to us, prohibits an interested unitholder, defined as a person who owns
15
% or more of our outstanding common units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder without the approval of our board of managers and the vote of
66
2/3% of our outstanding Class B common units, excluding those held by the interested unitholder. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. In addition to limiting our ability to enter into transactions with PostRock or its affiliates, this provision of our operating agreement could have an anti-takeover effect with respect to transactions not approved in advance by our board of managers, including discouraging takeover attempts that might result in a premium over the market price for our common units. We believe the Section 203 restrictions related to these unit purchases expire in December 2014.
Sanchez-Related Announcements
In August 2013, SOG acquired certain of our Class A units and Class B common units and one Class Z unit in one transaction which represented a 19.5% ownership interest in us at March 31, 2014. These units were issued to SOG, along with cash, in exchange for oil and natural gas properties located in Texas and Louisiana.
In August 2013, the Company also entered into a Registration Rights Agreement with SOG pursuant to which the Company granted to SOG certain registration rights related to the unit consideration thereunder. Under the Registration Rights Agreement, the Company granted SOG demand registration rights with respect to the preparation and filing with the SEC of one or more registration statements for the purpose of registering the resale of the securities that will be registered.
Class C Management Incentive Interests
CEPH, a subsidiary of Exelon, holds the Class C management incentive interests in CEP. These management incentive interests represent the right to receive
15%
of quarterly distributions of available cash from operating surplus after the Target Distribution (as defined in our operating agreement) has been achieved and certain other tests have been met. None of these applicable tests have yet to be met and CEPH has not been entitled to receive any management incentive interest distributions or share in distributions upon liquidation.
Class D Interest
The majority of our properties in the Robinson’s Bend Field were subject to a non-operated net profits interest (NPI) held by Torch Energy Royalty Trust (the Trust). Through the NPI, the Trust was entitled to a royalty payment, calculated as a percentage of the net revenue from specified wells in the Robinson’s Bend Field (the Trust Wells).
Under the terms of the NPI and related contractual arrangements, the royalty payment we were required to make to the Trust under the NPI was calculated using a sharing arrangement with a pricing formula that had resulted in below-market prices and had the effect of keeping our payments to the Trust significantly lower than if such payments had been calculated on then prevailing market prices.
In order to address the risks of early termination, without the prior consent of our board of managers, of the sharing arrangement in respect of the calculation of amounts payable to the Trust for the NPI and the potential reduction in our revenues resulting therefrom, CHI contributed
$8.0
million to us for all of our Class D interests. This contribution was potentially to be distributed to CHI in
24
distributions over a period of approximately
six
years if the sharing arrangement remained in effect during that period. If the amounts payable by us to the Trust were not calculated based on the continued applicability of the sharing arrangement through December 31, 2012, unless such change was approved in advance by our board of managers and our conflicts committee, the following would occur: the Class D interests would cease receiving the cash distributions; and the Class D interest would only be returned the remaining undistributed amount of the $8.0 million contribution under certain circumstances upon our liquidation.
No payments for the NPI were ever made to the Trust. On January 8, 2009, we were served by Trust Venture, on behalf of the Trust, with a purported derivative action filed in the Circuit Court of Tuscaloosa County, Alabama (the Circuit Court). The lawsuit
alleged, among other things, a breach of contract under the conveyance associated with the NPI and the agreement establishing the Trust and asserted that above market rates for services were paid, reducing the amounts paid to the Trust in connection with the NPI. The lawsuit sought unspecified damages and an accounting of the NPI. The lawsuit was settled in June 2011. The settlement with Trust Venture, its successor and the Trust provided, among other things, that we pay
$1.2
million to reimburse Trust Venture and its successor for their legal fees and expenses incurred in prosecuting the lawsuit and that we acquire the NPI from the Trust for
$1.0
million. When the NPI
was assigned to us by the Trust in the fourth quarter of 2011, the NPI was extinguished. We recognized a
$1.0
million charge to impair the value of the extinguished NPI contract that was acquired. The finalization of this settlement impacted our Class D interests.
CEPH, a subsidiary of Exelon and the successor to CHI, holds all of our Class D interests. Due to their contingently redeemable feature, the Class D interests were treated as temporary equity. Since the NPI is no longer being paid based upon the sharing arrangement and we have suspended distributions since June 2009, there should be no further distributions required on the Class D interests. Accordingly, the Class D interests were moved from temporary equity to permanent equity (Class A and Class B) in the fourth quarter of 2011. The Class D interests will remain outstanding until the liquidation of CEP and could receive up to
$6.7
million under certain circumstances at that time.
Class Z Unit
SOG holds the one Class Z unit of CEP. This one unit is a non-voting unit, except
for
voting as a separate class t
o
approve the issuance of additional Company securities, other than Class B common units, prior to the issuance of such securities. The Class Z unit is a non-economic interest, without any right to participate in distributions or allocations.
11.
UNIT-BASED
COMPENSATION
We have the following unit-based compensation plans:
We have the 2009 Omnibus Incentive Compensation Plan (Omnibus Plan), which is a plan under which restricted common unit awards are granted to certain employees in Texas. The Omnibus Plan provides for a variety of unit-based and performance-based awards, including unit options, restricted units, unit grants, notional units, unit appreciation rights, performance awards and other unit-based awards. Awards under the Omnibus Plan may be paid in cash, units or any combination thereof as determined by the compensation committee of our board of managers.
Restricted unit activity (number of units) under the Omnibus Plan was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
Average
|
|
|
Number of
|
|
Grant Date
|
|
|
Restricted
|
|
Fair Value
|
|
|
Units
|
|
Per Unit
|
|
|
|
|
|
|
Outstanding at December 31, 2013
|
|
336,551
|
|
$
|
3.29
|
Vested
|
|
(171,692)
|
|
|
3.33
|
Granted
|
|
-
|
|
|
-
|
Returned/Cancelled
|
|
(57,214)
|
|
|
3.33
|
Outstanding at March 31, 2014
|
|
107,645
|
|
$
|
3.20
|
We have the Long-Term Incentive P
lan
(L-TIP), which is a plan under which restricted common unit awards are granted to certain field employees in
Alabama, Kansas and Oklahoma and to certain employees in Texas.
Restricted unit activity (number of units) under the L-TIP Plan was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
Average
|
|
|
Number of
|
|
Grant Date
|
|
|
Restricted
|
|
Fair Value
|
|
|
Units
|
|
Per Unit
|
|
|
|
|
|
|
Outstanding at December 31, 2013
|
|
43,776
|
|
$
|
2.87
|
Vested
|
|
(16,415)
|
|
|
2.87
|
Granted
|
|
-
|
|
|
-
|
Returned/Cancelled
|
|
(5,469)
|
|
|
2.87
|
Outstanding at March 31, 2014
|
|
21,892
|
|
$
|
2.87
|
We recognized a
pproximately $
0.
1
million and $
0.4
million of non-cash compensation expense related to our unit-based compensation plans in the
three
months ended
March
3
1
, 201
4
, and
March 31
, 201
3
, respectively. As of
March
3
1
, 201
4
, we had approximately $
0.
4
million in unrecognized compensation expense related to our unit-based non-cash compensation plans expected to be recognized through
the first quarter of 2015.
12. DISTRIBUTIONS TO UNITHOLDERS
Beginning in June 2009, we suspended our quarterly distributions to unitholders. For each of the quarterly periods since June 2009, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions
.
13. MEMBERS’ EQUITY
201
4
Equity
At
March
31, 2014, we had
1,615,017
Class A units and
28,399,502
Class B common units outstanding, which included
129,537
unvested restricted common units issued under our
L-TIP
Plan and
342,803
unvested restricted common units issued under our Omnibus Plan.
A
t
March
3
1
, 201
4
, we had gran
ted
341,265
common units of the
450,000
common units available under our L-T
IP
Plan. Of these grants,
319,373
have
vested.
At
March
3
1
, 201
4
, we had granted
1,309,452
common units of the
1,650,000
common units available under our Omnibus Plan. Of these grants,
1,201,807
have
vested.
For the
three
months ended
March
3
1
, 201
4
,
62,683
common units
were
tendered by our employees for tax withholding purposes.
These units, costing approximately $
0.2
million, were returned to their respective plan and are available for future grants.
201
3
Equity
At
December
3
1
, 201
3
, we
had
1,615,017
Class A units and
28,462,185
Class
B common units outstanding, which included
43,776
unvested restricted common units issued under our L-T
IP
Plan and
336,551
unvested restricted common units issued under our Omnibus Plan.
At
December
3
1
, 201
3
, we had
granted
346,734
common
units of the
450,000
common units available under our L-T
IP
Plan. Of these grants,
302,958
have vested.
At
December
3
1
, 201
3
, we had
granted
1,366,666
common units of the
1,650,000
common units available under our Omnibus Plan. Of these grants,
1,030,115
have vested.
For the three months ended
December
31, 2013,
139,810
common units
were
tendered by our employees for tax withholding purposes. These units, costing approximately $
0.2
million
,
were
returned to their respective plan and are available for future grants.
1
4
. SUBSEQUENT EVENTS
The following events have occurred subsequent to the date of the balance sheet and prior to the filing of this Quarterly Report on Form 10-Q that could have a material impact on our consolidated financial statements or results of operations:
Acquisition of Properties
On April 9, 2014, we
acquired a
20
% working interest in
9
producing wells and other assets for $
1.4
million. These assets are located in LaSalle Parish, Louisiana and are operated by SOG. This purchase became effective May 1, 2014.
Settlement of PostRock Litigation
In connection with the settlement of the PostRock litigation settlement, discussed in Note 9, we received $
1.25
million on April 10, 2014, under our directors and officers insurance policy. This amount has been reflected as a reduction in general and administrative expense for the three months ended March 31, 2014, and included in accounts receivable, net at March 31, 2014.
Derivative Transactions
We entered into three new commodities swap transactions on April 29, 2014. Under these swap transactions we hedged
52,243
barrels of oil for the period May 2014 through December 2014 at a fixed price of $
98.01
per barrel;
83,017
barrels of oil for the period January 2015 through December 2015 at a fixed price of $
91.07
per barrel and
148,853
barrels of oil for the period January 2016 through December 2016 at a price of $
85.70
per barrel.
Increase in Reserve-Based Credit Facility Borrowing Capacity
On May 6, 2014, our borrowing base under our reserve-based credit facility was increased from $
55.0
million to $
70.0
million. The lenders and their percentage commitments in the reserve-based credit facility remained the same.
Shared Services Agreement
On May 8, 2014, the Company and SP Holdings, LLC (the Manager), an affiliate of SOG, entered into a Shared Services Agreement (the Services Agreement) pursuant to which Manager will provide all services that the Company requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, professionals and acquisition, disposition and financing services. In connection with providing the services under the Services Agreement, Manager will receive compensation consisting of: (i) a quarterly fee equal to
0.375
% of the value of the Company’s properties other than its assets located in the Mid-Continent region, (ii) a $
1,000,000
administrative fee, with $
500,000
paid on May 8, 2014 and $
500,000
to be paid on the date that Manager provides notice of its commitment to provide services under the Shared Services Agreement (the In-Service Date), (iii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iv) for each asset acquisition, asset disposition and financing, a fee not to exceed
2
% of the value of such transaction. Each of these fees, not including the reimbursement of costs, will be paid in cash unless Manager elects for such fee to be paid in equity by the Company. In addition, upon the first acquisition of assets from an affiliate of Manager, the Company is required to amend its operating agreement and issue a new class of incentive distribution rights to Manager.
The Services Agreement has a
ten
-year term and will be automatically renewed for an additional
ten
years unless both Manager and the Company provide notice to terminate the agreement. The Services Agreement can be terminated early (i) by either party at any time after
24
months from the In-Service Date with
six
months’ notice to the other party, (ii) by either party if there is an uncured material breach thereunder by the other party or (iii) by the Company if there is a change in control of Manager and the Company pays the termination payment discussed below. If there is a termination of the Services Agreement other than by either party at the end of the agreement’s term, by the Company for a breach by Manager, by Manager because the conditions precedent to the In-Service Date have not been satisfied or by either party because the In-Service Date has not occurred by December 31, 2014, then the Company will owe a termination payment to Manager equal to $
5,000,000
plus
5
% of the transaction value of all asset acquisitions theretofore consummated; if the Company terminates after the 24-month anniversary of the In-Service Date upon six months’ notice, the Company will also owe to Manager all costs and expenses of Manager that result from such termination.
Contract Operating Agreement
On May 8, 2014, the Company and SOG entered into a Contract Operating Agreement (the Operating Agreement) pursuant to which SOG has agreed either to provide all services to operate, develop and produce the Company’s oil and natural gas properties or
to engage a third-party operator to do so, other than with respect to the Company’s properties in the Mid-Continent region. In connection with providing services under the Operating Agreement, SOG will be reimbursed for all direct charges incurred under COPAS.
Transition and Assistance Agreement
On May 8, 1014, the Company, Manager and SOG entered into a Transition and Assistance Agreement (the Transition Agreement) pursuant to which the Company has agreed to make available to Manager and SOG certain of the Company’s employees for SOG or Manager to provide services under the Services Agreement and Operating Agreement. No compensation is paid by any party for the provision or use of employees under the Transition Agreement. All employees remain under the day-to-day control of the Company, and the Company retains the right to terminate employees and has no obligation to hire new employees. SOG has the right to hire any Company employees and thereafter, SOG will be responsible for all costs and expenses for such employees.
Seismic License Agreement
On May 8, 2014, the Company, SOG and certain subsidiaries of the Company entered into a Geophysical Seismic Data Use License Agreement (the License Agreement) pursuant to which SOG provides to the Company a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to the Company’s oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors.
Compensation Awards
On May 6, 2014, the Compensation Committee of the Company’s Board of Managers awarded retention awards of notional or phantom units to certain employees of the Company, including the Chief Executive Officer and Chief Financial Officer, to induce them to remain employed with the Company for a certain period of time. The awards were granted under the Company’s Omnibus Plan and L-TIP Plan. Under the terms of the awards, the notional or phantom units will fully vest on the earliest to occur of March 15, 2015, the occurrence of the In-Service Date or the consummation of a change of control, as defined in the applicable award agreement. Any notional or phantom units that are unvested on the date on which the recipient’s employment with the Company is terminated shall be forfeited.