| • QUARTERLY REPORT PURSUANT TO SECTIONS 13 OR 15(D • EX-31.1 • EX-31.2 • EX-32.1 • EX-32.2 • XBRL INSTANCE DOCUMENT • XBRL TAXONOMY EXTENSION SCHEMA DOCUMENT • XBRL TAXONOMY EXTENSION CALCULATION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION DEFINITION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION LABELS LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE DOCUMENT | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2012
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-34722
PAA Natural Gas Storage, L.P. (Exact name of registrant as specified in its charter)
(713) 646-4100 (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 preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o 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):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No
As of August 2, 2012, there were 59,193,825 common units outstanding.
PAA NATURAL GAS STORAGE, L.P. AND SUBSIDIARIES
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PAA Natural Gas Storage, L.P. and Subsidiaries Condensed Consolidated Balance Sheets (in thousands, except units)
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PAA Natural Gas Storage, L.P. and Subsidiaries Condensed Consolidated Statements of Operations (in thousands, except per unit data)
(1) Excludes Series B subordinated units. See Note 8, “Net Income per Limited Partner Unit.”
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PAA Natural Gas Storage, L.P. and Subsidiaries Condensed Consolidated Statements of Comprehensive Income (in thousands)
PAA Natural Gas Storage, L.P. and Subsidiaries Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income/(Loss) (in thousands)
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PAA Natural Gas Storage, L.P. and Subsidiaries Condensed Consolidated Statements of Cash Flows (in thousands)
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PAA Natural Gas Storage, L.P. and Subsidiaries Condensed Consolidated Statement of Changes in Partners’ Capital (in thousands)
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
PAA Natural Gas Storage, L.P. and Subsidiaries Notes to the Condensed Consolidated Financial Statements (unaudited)
Note 1—Organization and Basis of Presentation
PAA Natural Gas Storage, L.P. (the “Partnership” or “PNG”) is a Delaware limited partnership formed on January 15, 2010 to own the natural gas storage business of Plains All American Pipeline, L.P. (“PAA”). The Partnership is a fee-based, growth-oriented partnership engaged in the ownership, acquisition, development, operation and commercial management of natural gas storage facilities.
We currently own and operate three natural gas storage facilities located in Louisiana, Mississippi and Michigan. Our Pine Prairie and Southern Pines facilities are recently constructed, high-deliverability salt cavern natural gas storage complexes located in Evangeline Parish, Louisiana and Greene County, Mississippi, respectively. Our Bluewater facility is a depleted reservoir natural gas storage complex located approximately 50 miles from Detroit in St. Clair County, Michigan. As of June 30, 2012, through these facilities, PNG had a total of eight operational salt storage caverns and two depleted reservoirs used for natural gas storage, with an aggregate owned working gas storage capacity of approximately 86 billion cubic feet (“Bcf”). We also own PNG Marketing, LLC, a wholly owned commercial optimization company, that captures short-term market opportunities by leasing a portion of our storage capacity and engaging in related commercial marketing activities.
As of June 30, 2012, PAA owned approximately 64% of the equity interests in the Partnership, including our 2.0% general partner interest and limited partner interests consisting of 28,155,526 common units, 11,934,351 Series A subordinated units and 13,500,000 Series B subordinated units.
The accompanying condensed consolidated interim financial statements include the accounts of PNG and its subsidiaries, all of which are wholly owned, and should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2011 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to the Partnership. The condensed balance sheet data as of December 31, 2011 was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP. The results of operations for the three and six months ended June 30, 2012 should not be taken as indicative of the results to be expected for the full year.
As used in this document, the terms “we,” “us,” “our” and similar terms refer to the Partnership, unless the context indicates otherwise.
Property and Equipment
During the six months ended June 30, 2011, we received cash of approximately $7.2 million under a state incentive program for jobs creation. This incentive payment, which was determined based on applicable capital expenditures, was accounted for as a refund of sales tax previously paid and reduced the carrying value of our applicable property and equipment.
Note 2—Recent Accounting Pronouncements
Other than as discussed below and in our 2011 Annual Report on Form 10-K, no new accounting pronouncements have become effective during the six months ended June 30, 2012 that are of significance or potential significance to us.
In September 2011, the FASB issued guidance with the purpose of simplifying the goodwill impairment test by permitting entities to perform a qualitative assessment to determine whether further impairment testing is necessary. If qualitative factors indicate that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, an entity need not perform the two-step goodwill impairment test. This guidance became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Our adoption did not have a material impact on our financial position, results of operations or cash flows.
In June 2011, the FASB issued guidance regarding the presentation of other comprehensive income, which was later amended in December 2011, with the purpose of increasing the prominence of other comprehensive income in financial statements. This guidance, as amended, requires entities to present comprehensive income in either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance became effective for interim and annual periods beginning after December 15, 2011. We adopted the guidance, as amended, on January 1, 2012. Since this guidance only impacts the presentation of comprehensive income and does not change the composition or calculation of such financial information, adoption did not have a material impact on our financial position, results of operations or cash flows.
In May 2011, the FASB issued guidance to amend certain fair value measurement and disclosure requirements in an effort to improve consistency with international reporting standards. The amendments generally clarify that the concepts of highest and best use and valuation premise in fair value measurement are relevant only when measuring the fair value of non-financial assets and are not relevant when measuring the fair value of financial assets or of liabilities. In addition, the guidance expanded disclosure requirements associated with (i) unobservable inputs for Level 3 fair value measurements and (ii) items that are not measured at fair value in the financial statements, but for which fair value is required to be disclosed. This guidance became effective prospectively for interim and annual reporting periods beginning after December 15, 2011. We adopted this guidance on January 1, 2012. Other than requiring additional disclosure, which is included in Note 7, our adoption did not have a material impact on our financial position, results of operations or cash flows.
We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At June 30, 2012 and December 31, 2011, substantially all of our accounts receivable were current and we had no allowance for doubtful accounts.
Our accounts receivable are from a broad mix of customers, including local gas distribution companies, electric utilities, pipelines, direct industrial users, electric power generators, marketers, producers, LNG importers and affiliates of such entities.
To mitigate credit risks related to our accounts receivable, we have in place a rigorous credit review process. We closely monitor market conditions in order to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, parental guarantees or advance cash payments. In addition, we enter into netting arrangements (contractual agreements that allow us and the counterparty to offset receivables and payables against each other) that cover substantially all of our natural gas purchases and sales transactions and also serve to mitigate credit risk.
On February 9, 2011, we completed the acquisition of SG Resources Mississippi, L.L.C., owner of the Southern Pines Energy Center natural gas storage facility (the “Southern Pines Acquisition”). The purchase price was approximately $765 million (approximately $750 million net of cash and other working capital acquired).
The purchase price allocation was as follows (in millions):
In conjunction with the Southern Pines Acquisition, we arranged financing totaling approximately $800 million to fund the purchase price, closing costs and the first 18 months of expected expansion capital. The financing consisted of $200 million of borrowings under a promissory note from PAA (see Note 7) and approximately $600 million from the issuance of our common units (see Note 9).
During the six months ended June 30, 2011, we incurred approximately $4.1 million of acquisition-related costs associated with the Southern Pines Acquisition. Such costs are reflected as a component of general and administrative expenses in our condensed consolidated statement of operations.
In May 2011, we entered into an agreement with the former owners of SG Resources Mississippi, LLC with respect to certain outstanding issues and purchase price adjustments as well as the distribution of the remaining purchase price that was escrowed at closing. Pursuant to this agreement, we received approximately $10 million and the balance was remitted to the former owners. Funds received by us have been and will continue to be used to fund anticipated facility development and other related costs identified subsequent to closing. None of these funds were spent during the six months ended June 30, 2012.
Pro Forma Results
Selected unaudited pro forma results of operations for the six months ended June 30, 2011, assuming the Southern Pines Acquisition had occurred on January 1, 2010, are presented below (in thousands, except per unit amounts):
(1) Amount for the period excludes approximately $4.1 million of acquisition costs associated with the Southern Pines Acquisition. (2) Excludes Series B subordinated units. See Note 8, “Net Income per Limited Partner Unit.”
Inventory and base gas consisted of the following (natural gas volumes in thousands of Mcf and total values in thousands):
(1) Total value represents a weighted average associated with various locations; accordingly, these values may not coincide with any published benchmarks for such products. (2) Includes fuel inventory held for operational purposes. (3) As of December 31, 2011, the carrying value of natural gas inventory reflects lower of cost or market adjustments of approximately $6.0 million. No lower of cost or market adjustments were included in the carrying value of natural gas inventory as of June 30, 2012. Lower of cost or market adjustments are reflected as a component of natural gas sales costs in our accompanying condensed consolidated statement of operations. The impacts of such adjustments are generally offset by the recognition of unrealized gains on derivative instruments (see Note 11) being utilized to hedge the future sales of our natural gas inventory. (4) Natural gas inventory balances exclude derivative gains and losses associated with settled derivatives which were entered into to hedge natural gas inventory purchases. As of June 30, 2012, net deferred losses of approximately $28.3 million associated with settled derivatives are reflected as a component of accumulated other comprehensive income/(loss) in our condensed consolidated balance sheet. Such amounts will be reclassified to earnings in conjunction with an earnings impact associated with the applicable purchase inventory (typically when such inventory is sold).
The table below reflects our changes in goodwill for the period indicated (in thousands):
On June 1, 2012, the Partnership and PAA entered into an amendment (the “PAA Promissory Note Amendment”) to the PAA Promissory Note, which was originally entered into during 2011. The PAA Promissory Note Amendment modified the terms of the PAA Promissory Note by (i) reducing the interest rate from 5.25% per annum to 4.00% per annum and (ii) extending the scheduled maturity date from February 9, 2014 to June 1, 2015. The remaining terms of the PAA Promissory Note were unchanged.
On June 27, 2012 we partially exercised the accordion feature of our revolving credit facility, increasing borrowing capacity from $250 million to $350 million. Also on June 27, 2012, we reached an agreement with applicable lenders to amend certain terms and provisions of our senior unsecured credit agreement (the “Credit Agreement Amendment”). Pursuant to the Credit Agreement Amendment, the revolving credit facility commitments may be further increased to $550 million, subject to, among other terms and conditions, obtaining additional or increased lender commitments. The Credit Agreement Amendment also provides for one or more one-year extensions of the maturity date of the revolving credit facility and the date (the “GO Bond Mandatory Put Date”) on which the Purchasers of the GO Bond Term Loans have the right to require the Partnership to repurchase such loans, in each case, subject to applicable lender approval and other terms and conditions set forth in the credit agreement, as amended. The revolving credit facility will expire and all amounts outstanding under it will mature on August 19, 2016 unless, such maturity date is extended pursuant to the terms of the credit agreement, as amended, and the purchasers of the two GO Bond Term Loans have the right to put, at par, to the Partnership the GO Bond Term Loans on August 19, 2016 unless such GO Bond Mandatory Put Date is extended pursuant to the terms of the credit agreement, as amended. The maturity dates for the GO Bonds, which mature by their terms on May 1, 2032 and August 1, 2035, respectively, were not changed by the Credit Agreement Amendment. Provisions of the credit agreement providing for the calculation and payment of interest or fees and regarding covenants, including the financial covenants, events of default and lender remedies were substantially unchanged by the Credit Agreement Amendment, as were the terms providing for the issuance of letters of credit.
Debt consisted of the following (in thousands):
(1) We classify as short-term debt any borrowings under our senior unsecured revolving credit facility that have been designated as working capital borrowings and must be repaid within one year. Such borrowings are primarily related to a portion of our funded hedged natural gas inventory or NYMEX margin requirements. Approximately $0.3 million and $0.5 million of interest expense attributable to such borrowings is reflected as a component of natural gas sales costs in the accompanying condensed consolidated statements of operations for the three and six months ended June 30, 2012, respectively.
(2) We estimate that the fair value of borrowings outstanding under our credit agreement (including the revolving credit facility and GO Bond Term Loans) and the PAA Promissory Note approximate carrying value due to the short maturity of both obligations and the variable interest rate terms set forth under our credit agreement. Our fair value estimate for amounts outstanding under our credit agreement is based upon observable market data and is classified with Level 2 of the fair value hierarchy. With regard to the PAA Promissory Note, our fair valuation estimation process incorporates our estimated credit spread, an unobservable input. As such, we consider this to be a Level 3 measurement within the fair value hierarchy.
Our revolving credit facility includes the ability to issue letters of credit. As of June 30, 2012, we had $3.8 million of outstanding letters of credit under our revolving credit facility.
As of June 30, 2012, we were in compliance with the covenants required by our credit agreement.
Interest payments on the PAA Promissory Note (which commenced on December 31, 2011) are paid semiannually on the last business day of June and December. Interest paid to PAA during the six months ended June 30, 2012 was approximately $5.0 million. There was no accrued interest payable due under the PAA Promissory Note as of June 30, 2012 or December 31, 2011.
Capitalized interest for the three and six months ended June 30, 2012 was $2.1 million and $4.5 million, respectively, and $3.1 million and $5.7 million for the three and six months ended June 30, 2011, respectively.
Note 8—Net Income per Limited Partner Unit
Basic and diluted net income per limited partner unit is determined pursuant to the two-class method for Master Limited Partnerships as prescribed in the FASB guidance. The two-class method is an earnings allocation formula that determines earnings to our general partner, limited partner interests and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings. Under this method, all earnings are allocated to our general partner, limited partner interests and participating securities based on their respective rights to receive distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective. We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, limited partner interests and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.
The following table sets forth the computation of basic and diluted earnings per limited partner unit for the three and six months ended June 30, 2012 and 2011 (amounts in thousands, except per unit data):
(1) Participating securities consist of LTIP awards (see Note 10) containing vested distribution equivalent rights which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units. (2) For each of the periods presented, our Series B subordinated units were not entitled to participate in our earnings, losses or distributions in accordance with the terms of our partnership agreement as necessary performance conditions have not been satisfied. As a result, no earnings were allocated to the Series B subordinated units in our determination of basic and diluted net income per limited partner unit. (3) Substantially all of our LTIP awards (see Note 10), which are classified as equity awards, contain provisions whereby vesting occurs only upon the satisfaction of a performance condition. None of the performance conditions on such awards had been satisfied during any of the periods presented. As such, our outstanding LTIP awards as of June 30, 2012 did not have a material impact in our determination of diluted net income per limited partner unit. (4) The conversion of (i) our Series A subordinated units to common units and (ii) our Series B subordinated units to Series A subordinated units or common units is subject to certain performance conditions. None of these performance conditions had been satisfied as of June 30, 2012 therefore, there is no dilutive impact of such units in our determination of diluted net income per limited partner unit.
Note 9—Partners’ Capital and Distributions
Modification of Terms of Series B Subordinated Units
In February 2012, we modified the terms of the Partnership’s 13.5 million Series B subordinated units, which modification was approved by PAA, the owner of all of the Series B subordinated units. The Partnership’s Series B subordinated units do not participate in quarterly distributions. Instead, the Series B subordinated units convert into Series A subordinated units or common units in five distinct tranches upon the achievement of defined benchmarks tied to the amount of capacity in service at Pine Prairie and increases in our quarterly distributions. The modification increases the quarterly distribution benchmark for the first three of the five tranches, totaling 7.5 million Series B subordinated units in the aggregate, to an annualized level of $1.71 per unit. Previously, the quarterly distribution levels required to cause conversion for these three tranches were at annualized levels of $1.44, $1.53 and $1.63 per unit. The modification, which was made in recognition of the continued challenging market conditions facing the natural gas storage business, benefits our common unitholders by reducing the number of units on which distributions would otherwise be required to be paid in the case of distributions below the annualized level of $1.71. The following table presents the operational and financial benchmarks, as modified, for conversion of the Series B subordinated units into Series A subordinated units for each tranche (units in millions):
(1) For satisfaction of this benchmark, PNG must, for two consecutive quarters, (i) generate distributable cash flow sufficient to pay a quarterly distribution of at least the annualized distribution benchmark on the weighted average number of common units and Series A subordinated units outstanding during such quarter plus all of such Series B subordinated units and (ii) distribute available cash of at least the annualized distribution benchmark on all outstanding common units and Series A subordinated units and the corresponding distributions on PNG’s general partner’s 2% interest and the related distributions on the incentive distribution rights. See Note 6 to our consolidated financial statements included in Part IV of our 2011 Annual Report on Form 10-K for a complete discussion of our Series B subordinated units.
Outstanding Units
From December 31, 2011 through June 30, 2012, there were no changes in our issued and outstanding common, Series A subordinated or Series B subordinated units.
Distributions
The following table details the distributions declared for 2012 quarterly periods or paid during the six months ended June 30, 2012 (in millions, except per unit amounts):
(1) Payable to unitholders of record on August 3, 2012, for the period April 1, 2012 through June 30, 2012.
Equity Offerings
On February 8, 2011, in connection with the Southern Pines Acquisition, we completed the sale in a private placement of approximately 17.4 million common units to third-party purchasers and approximately 10.2 million common units to PAA for total proceeds of approximately $600 million, including PAA’s proportionate general partner contribution.
Note 10—Equity Compensation Plans
Long Term Incentive Plan (“LTIP”)
For discussion of our equity compensation awards, see Note 12 to our consolidated financial statements included in Part IV of our 2011 Annual Report on Form 10-K.
In February 2012, the Board of Directors of our general partner approved the modification of certain equity compensation awards previously granted under the 2010 LTIP Plan. As a result of the modification, approximately 232,500 equity-classified phantom unit awards will now vest in the following manner: (i) approximately 70,000 awards, with distribution equivalent rights also modified to begin payment in February 2012, will vest upon the date we pay an annualized distribution of at least $1.45, (ii) approximately 70,000 awards, with distribution equivalent rights also modified to begin payment in May 2013, will vest upon the date we pay an annualized distribution of at least $1.50 and (iii) the remainder, with distribution equivalent rights also modified to begin payment in May 2014, will vest upon the date we pay an annualized distribution of at least $1.55. Fifty percent of any awards that have not vested as of the November 2016 distribution date will vest at that time and the remainder will expire. Additionally, 232,500 of equity-classified phantom unit awards with vesting terms originally tied to the conversion of our Series A and Series B subordinated units were modified such that all these awards will now fully vest upon conversion of the Series A subordinated units to common units. Distribution equivalent rights were also granted with respect to these awards beginning February 2012.
Our equity compensation activity for awards denominated in PNG units is summarized in the following table (units in thousands):
(1) Amounts do not include Class B units of PNGS GP LLC or transaction awards granted by PAA. (2) Weighted average grant date fair value per unit for PNG units outstanding at June 30, 2012, reflects the impact of the modification of PNG awards during February 2012, as discussed above.
The table below summarizes the expense recognized and unit or cash settled vestings related to equity compensation awards during the three and six months ended June 30, 2012 and 2011 (in thousands):
(1) Includes expense associated with transaction awards granted by PAA and denominated in PNG units owned by PAA. These awards, which were granted in September 2010, are not included in units outstanding above. The entire economic burden of these agreements will be borne solely by PAA and will not impact our cash or units outstanding. The individuals that received these awards are officers of PAA, but because they also serve as officers of PNG and PNG benefits as a result of the services they provide, we recognize the grant date fair value of these awards as compensation expense over the service period, with such expense recognized as a capital contribution. We recognized approximately $0.3 million and $0.8 million of compensation expense associated with these equity-classified awards during the three and six months ended June 30, 2012, respectively. We recognized approximately $0.8 million and $1.9 million of compensation expense associated with these equity-classified awards during the three and six months ended June 30, 2011, respectively. (2) Includes cash payments made in conjunction with the settlement of PAA common unit denominated LTIP awards.
Note 11—Derivatives and Risk Management Activities
We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our risk management strategies utilize various derivatives to manage our exposure to both commodity price risk and interest rate risk. At the inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, as well as our risk management objective for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives within the hedging relationship are highly effective in offsetting changes in cash flows of hedged items. Our policy is to use derivatives only for hedging purposes and not for the purpose of speculating.
Commodity Price Risk Hedging
Our core business activities in which we utilize derivatives to manage exposure associated with commodity price risk (resulting from natural gas price fluctuation in spot and forward markets, among other factors) and to optimize profits are as follows:
Merchant Storage Activities- When contango market conditions exist (forward prices exceed spot prices), our commercial optimization company may utilize our storage capacity to purchase natural gas and hold it for sale in a forward month. Additionally, to further optimize profits when favorable market conditions exist, our commercial optimization company may sell owned natural gas inventory and repurchase it at a lower price in a forward month.
Operational Gas Purchases and Sales- We purchase and sell natural gas for operational purposes at our storage facilities. These activities primarily consist of the purchase of base gas for caverns under development or anticipated future development of our facilities. We also sell fuel inventory collected from our customers under the terms of our storage contracts.
Crude Oil Sales- We sell crude oil and liquids produced in conjunction with the operation of our Bluewater facility.
The risk management strategies we utilize to manage commodity price risk exposure associated with these core activities include the use of exchange-cleared futures, swaps (including basis and index swaps) and options.
In conjunction with our merchant storage activities, we typically enter into a spread position to hedge both purchases and sales of natural gas in the respective months. The hedging instrument for each respective month is settled concurrent with the applicable physical transaction. This enables us to maintain a balanced position when our hedging instruments are aggregated with physical purchases and sales. The fair value of our derivative spread positions are exposed to changes in the spread (the difference in commodity price between two distinct months). However, the fair value of our derivative spread positions are not exposed to changes in outright prices and are offset by the corresponding change in fair value of the physical position that is being hedged.
The following table summarizes open derivative positions utilized in commodity price risk management strategies as of June 30, 2012:
(1) Volumes presented represent net position through the month noted. (2) Excludes spread positions through September 2013, which consist of an offsetting purchase and sale between two different months, of 21.0 Bcf. (3) Includes 4.1 Bcf of anticipated base gas purchases through April 2016.
Interest Rate Risk Hedging
We use interest rate derivatives to hedge the underlying benchmark interest rate associated with borrowings outstanding under our debt facilities. During June 2011 and August 2011, we entered into three interest rate swaps to fix the interest rate on a portion of our outstanding debt. The swaps have an aggregate notional amount of $100 million with an average fixed rate of 0.95%. Two of these swaps terminate in June 2014 and the remaining swap terminates in August 2014. These swaps are designated as cash flow hedges.
Summary of Financial Statement Impact
For derivatives that qualify as a cash flow hedge, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions impact earnings. Derivatives that do not qualify or were not designated for hedge accounting, and the portion of cash flow hedges that are not highly effective in offsetting change in cash flows of the hedged items, are recognized in earnings each period.
A summary of the impact of our derivative activities recognized in earnings for the three and six months ended June 30, 2012 is as follows (in thousands):
A summary of the impact of our derivative activities recognized in earnings for the three and six months ended June 30, 2011 is as follows (in thousands):
(1) Amounts reported as a component of Natural gas sales represent derivative gains and losses that were reclassified from AOCI to earnings during the period to coincide with the earnings impact of the respective hedged transaction. (2) Amounts reported as a component of Other revenues include the ineffective portion of our cash flow hedges recognized in earnings. (3) Amounts include realized and unrealized gains or losses for derivatives that did not qualify or were not designated for hedge accounting during the period. (4) Unrealized gains of approximately $3.9 million, recorded as a component of Natural gas sales costs, were reclassified from AOCI to earnings during the six months ended June 30, 2012 to offset a lower of cost or market adjustment relating to the carrying value of our inventory.
The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of June 30, 2012 (in thousands):
The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of December 31, 2011 (in thousands):
Accumulated Other Comprehensive Income
As of June 30, 2012, there was a net loss of $25.1 million deferred in AOCI. Amounts deferred in AOCI include amounts associated with settled derivatives for which the underlying anticipated hedge transactions are still probable of occurring. The deferred loss in AOCI is expected to be reclassified to future earnings contemporaneously with the earnings recognition of the underlying hedged transactions. Certain underlying hedged transactions are for base gas purchases or other capital expansion expenditures. As we account for base gas as a long-term asset, which is not subject to depreciation, amounts related to base gas will not be reclassified to future earnings until such gas is sold or in the event an impairment charge is recognized in the future. Amounts related to other capital expansion activities will be reclassified to future earnings over the estimated useful life of the applicable asset. Deferred losses associated with capital expansion activities of approximately $12.7 million (including $10.3 million associated with base gas purchases) are included in AOCI as of June 30, 2012. Remaining amounts in AOCI as of June 30, 2012 are associated with both open and settled derivative positions. Of the total net loss deferred in AOCI at June 30, 2012, we expect to reclassify a net loss of approximately $12.0 million to earnings in the next twelve months. The remaining net loss will be reclassified to earnings through 2014. Amounts deferred are predominately based on market prices at the current period end, thus actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.
During the three and six months ended June 30, 2012, we reclassified gains of approximately $0.4 million and $0.5 million, respectively, from AOCI to natural gas sales revenues as a result of anticipated hedged transactions no longer being considered probable of occurring. During the three and six months ended June 30, 2011, we reclassified gains of approximately $0.7 million from AOCI to natural gas sales revenues as a result of anticipated hedged transactions no longer being considered probable of occurring.
Amounts recognized in AOCI for derivatives and amounts reclassified to earnings during the three and six months ended June 30, 2012 and 2011 are as follows (in thousands):
(1) Amounts reflect net unrealized derivative gains and losses deferred in AOCI for the period. Negative amounts represent a net deferral of losses and positive amounts reflect a net deferral of gains on the applicable activity. (2) Reclassification adjustments represent transfers of deferred gains and losses out of AOCI and into earnings for the period. Negative amounts represent the reclassification of previously deferred net gains into earnings and positive amounts represent the reclassification of previously deferred net losses into earnings for the period. Reclassification adjustments may include realization of amounts originally deferred to AOCI in both the current period as well as prior periods.
Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting agreement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our commodity derivatives, which are all exchange-traded or exchange-cleared, are transacted through a brokerage account and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or receipt of variation margin. As of June 30, 2012, we had a net broker payable of approximately $6.9 million (consisting of initial margin of $5.0 million decreased by $11.9 million of variation margin paid to us). Our interest rate derivatives, which are over-the-counter instruments, do not have margin requirements. At June 30, 2012 and 2011, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings.
Recurring Fair Value Measurements
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and 2011. Financial assets and liabilities are classified in their entirety 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, which affects the placement of assets and liabilities within the fair value hierarchy levels.
(1) Derivative assets and (liabilities) are presented above on a net basis but do not include any related cash margin deposits.
The determination of the fair values above includes not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of our nonperformance risk on our liabilities. The fair value of our commodity derivatives and interest-rate derivatives includes adjustments for credit risk. There were no changes to any of our valuation techniques during the period.
Note 12—Commitments and Contingencies
Litigation
We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
Environmental
We may experience releases of natural gas, brine, crude oil or other contaminants into the environment, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such releases from our assets may substantially affect our business. As of June 30, 2012, we have not identified any such material obligations.
Insurance
A natural gas storage facility, associated pipeline header system and gas handling and compression facilities may suffer damage as a result of an accident, natural disaster or terrorist activity. These hazards can cause personal injury and loss of life, severe damage to or destruction of property, base gas, or equipment, pollution or environmental damage, or suspension of operations. We maintain various types of insurance under PAA’s insurance program that we consider adequate to cover our operations and properties. Such insurance covers our assets in amounts management considers reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating natural gas storage facilities, associated pipeline header systems, and gas handling and compression facilities, including the potential loss of significant revenues.
The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage with respect to our operations. In the future, we may not be able to maintain insurance at levels that we consider adequate for rates we consider reasonable. As a result, we may elect to self-insure or utilize higher deductibles in certain insurance programs. For example, the market for hurricane-or windstorm-related property damage coverage has remained difficult the last few years. The amount of coverage available has been limited, and costs have increased substantially with the combination of premiums and deductibles.
In 2011, we elected not to renew our hurricane insurance and, instead, self-insure this risk. This decision does not affect our third-party liability insurance, which still covers hurricane-related liability claims and which we have renewed at our historic coverage levels. In addition, although we believe that we have established adequate reserves to the extent such risks are not insured, costs incurred in excess of these reserves may be higher and may potentially have a material adverse effect on our financial conditions, results of operations or cash flows.
Property Tax Matter
During the second quarter of 2012, certain outstanding property tax billing disputes with Evangeline Parish were resolved and approximately $1.4 million was returned to us. The resolution of such disputes did not have any effect on our results of operations for the period.
We manage our operations through three operating segments, Bluewater, Pine Prairie and Southern Pines. We have aggregated these operating segments into one reporting segment, Gas Storage. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including adjusted EBITDA, volumes, adjusted EBITDA per thousand cubic feet (“Mcf”) and maintenance capital expenditures. We have aggregated our three operating segments into one reportable segment based on the similarity of their economic and other characteristics, including the nature of services provided, methods of execution and delivery of services, types of customers served and regulatory requirements. We define adjusted EBITDA as earnings before interest expense, taxes, depreciation, depletion and amortization, equity compensation plan charges, unrealized gains and losses from derivative activities and other adjustments for the impact of unique and infrequent items, items outside of management’s control and/or items that are not indicative of our core operating results and business outlook, which we refer to as “selected items impacting comparability” or “selected items.” The measure above excludes depreciation, depletion and amortization as we believe that depreciation, depletion and amortization are largely offset by repair and maintenance capital investments. Maintenance capital consists of expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating capability, service capability, and/or functionality of our existing assets.
The following table reflects certain financial data for our reporting segment for the periods indicated (in thousands):
The following table reconciles Adjusted EBITDA to consolidated net income (in thousands):
Note 14—Related Party Transactions
In addition to transactions between PNG and PAA discussed in Notes 4, 7, 9, 10 and 12, additional activities between PNG and PAA are discussed below.
Total costs reimbursed by us to PAA for the three and six months ended June 30, 2012, were $4.1 million and $8.8 million, respectively; and $4.4 million and $8.1 million for the three and six months ended June 30, 2011, respectively. Of these amounts approximately $0.9 million and $1.8 million and $0.9 million and $ 1.8 million, during the three and six month periods ended June 30, 2012 and 2011, respectively, were allocated costs for shared services (including personnel costs) and the remainder consisted of direct costs that PAA paid on our behalf along with our allocation of insurance premiums for participation in PAA’s insurance program.
As of June 30, 2012 and December 31, 2011, PNG had amounts due to PAA of approximately $0.1 million and $0.6 million, respectively, included in accounts payable and accrued liabilities on our accompanying condensed consolidated balance sheet. Such amounts include accrued interest, if any, due under the PAA Promissory Note (see Note 7).
As of June 30, 2012 and December 31, 2011, PNG’s obligation for unvested equity-based compensation awards for which we are required to reimburse PAA upon vesting and settlement was approximately $1.0 million and $1.2 million, respectively.
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