Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or
Form 40-F:
x
Form 20-F
¨
Form 40-F
Indicate by check mark if the registrant is submitting the Form 6-K in paper as
permitted by Regulation S-T Rule 101(b)(1):
¨
Indicate by check mark if the registrant is
submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):
¨
Indicate by
check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:
¨
Yes
x
No
If
Yes is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):
n/a
Petrohawk Energy Corporation (Petrohawk) provides periodic reports to holders of Petrohawks senior notes as required in accordance with the reporting
covenants under the applicable indentures. A copy of Petrohawks March 2014 financial report (Quarterly Report) is attached, and will be provided to the holders of Petrohawks outstanding senior notes today.
Petrohawks financial statements are prepared in accordance with United States accounting standards whereas BHP Billiton Group financial statements are
prepared in accordance with International Financial Reporting Standards and include the impact of the purchase price paid for Petrohawk. In addition, the unaudited condensed consolidated financial statements contained in the Quarterly Report are
based on Petrohawks historical accounting activities and do not reflect the acquisition of Petrohawk by BHP Billiton or any of the fair value calculations that were performed in conjunction with the business combination accounting performed by
BHP Billiton. For the avoidance of doubt, the results of operations, financial position, cash flows and disclosures included in the Petrohawk Quarterly Report are not indicative of the contribution of Petrohawk to the potential results of BHP
Billiton.
BHP Billiton purchased Petrohawk on 20 August 2011 and therefore only consolidates Petrohawks results in its financial statements
from that date.
The accompanying unaudited condensed consolidated financial statements have been prepared in
accordance with accounting principles generally accepted in the United States. Petrohawk Energy Corporations (Petrohawk or the Company) parent, BHP Billiton Limited, prepares its condensed consolidated financial statements in accordance with
International Financial Reporting Standards (IFRS). The Company utilizes the full cost method of accounting for its oil and natural gas activities compared to BHP Billiton Limited which utilizes the successful efforts method of accounting. In
addition, the accompanying unaudited condensed consolidated financial statements are based on the Companys historical accounting activities and do not reflect the acquisition of the Company by BHP Billiton Limited or any of the fair value
allocations that were performed in conjunction with the business combination accounting performed by BHP Billiton Limited. Although the Company is wholly owned by BHP Billiton Limited, push down accounting from BHP Billiton Limited was deemed
inappropriate for the accompanying condensed consolidated financial statements due to the nature of Petrohawks agreement with the bondholders. For the avoidance of doubt, the results of operations, financial position, cash flows and
disclosures included in this document are
not
indicative of the potential contribution to the results of BHP Billiton Limited.
On February 19, 2013, the Directors adopted a resolution authorizing a change in the Companys fiscal year
from a calendar year to a July 1 through June 30 fiscal year, to align with BHP Billiton Limiteds fiscal year. The Companys transitional financial report to Security Holders covered the period from January 1, 2013 through
June 30, 2013, and included all information otherwise required in an annual report to bondholders under section 4.2 of the Indentures. This was issued to security holders of record on September 26, 2013.
As a result of the fiscal year change, please note that this is the third quarter report for the fiscal year ending June 30, 2014.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
The accompanying notes are an integral part of these unaudited condensed consolidated financial
statements.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. FINANCIAL STATEMENT PRESENTATION
Basis of
Presentation and Principles of Consolidation
Petrohawk Energy Corporation (Petrohawk or the Company) is engaged in the exploration,
development and production of predominantly oil and gas shale properties located in the United States. As further discussed under the heading
Merger
below, on August 25, 2011, BHP Billiton Limited, a corporation organized
under the laws of Victoria, Australia (BHP Billiton Limited), acquired 100% of the outstanding shares of Petrohawk through the merger of a wholly owned subsidiary of BHP Billiton Petroleum (North America) Inc., a Delaware corporation (which is a
wholly owned subsidiary of BHP Billiton Limited), with and into Petrohawk, with Petrohawk continuing as the surviving entity. Petrohawk remains an indirect, wholly owned subsidiary of BHP Billiton Limited. The unaudited condensed consolidated
financial statements include the accounts of all majority-owned, controlled subsidiaries of the Company. All intercompany accounts and transactions between Petrohawk and its controlled subsidiaries have been eliminated. These unaudited condensed
consolidated financial statements reflect, in the opinion of the Companys management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations
for, the periods presented. During interim periods, Petrohawk follows the accounting policies disclosed in its Annual Report. Please refer to the Notes to the Consolidated Financial Statements in the Transition Report to Security Holders dated
June 30, 2013, when reviewing interim financial results.
Subsequent events or transactions have been evaluated through the date of
issuance of this report in conjunction with the preparation of these unaudited condensed consolidated financial statements, and the Company has included those subsequent events within the following notes where applicable.
Merger
On July 14, 2011, the
Company entered into an agreement and plan of merger (Merger Agreement) with BHP Billiton Limited (Guarantor), BHP Billiton Petroleum (North America) Inc. (Parent), a Delaware corporation and a wholly owned subsidiary of Guarantor, and North America
Holdings II Inc., a Delaware corporation (Purchaser) and a wholly owned subsidiary of Parent. Pursuant to the Merger Agreement, on August 20, 2011, Purchaser accepted for payment all of the outstanding shares of the Companys common stock,
par value $0.001 per share, validly tendered and not validly withdrawn pursuant to the tender offer for $38.75 per share (Offer Price), net to the seller in cash. Additionally, and pursuant to the Merger Agreement, on August 25, 2011, Purchaser
merged with and into Petrohawk, with Petrohawk continuing as the surviving corporation in the merger and as a wholly owned subsidiary of Parent (the BHP Merger). Although the Company is a wholly owned subsidiary of BHP Billiton Limited, push down
accounting from BHP Billiton Limited was deemed inappropriate for the Companys condensed consolidated financial statements due to the nature of Petrohawks agreement with the bondholders. Thus, the condensed consolidated financial
statements are based on the Companys historical accounting activities and do not reflect the acquisition of the Company by BHP Billiton Limited or any of the fair value allocations that were performed in conjunction with the business
combination accounting performed by BHP Billiton Limited.
Change of Fiscal Year Changes to Comparative Periods
On February 19, 2013, the Directors adopted a resolution authorizing a change in the Companys fiscal year from a calendar year to a
July 1 through June 30 fiscal year, to align with BHP Billiton Limiteds fiscal year. The Companys transitional financial report to Security Holders covered the period from January 1, 2013 through June 30, 2013, and
included all information otherwise required in an annual report to bondholders under section 4.2 of the Indentures. This was issued to security holders of record on September 26, 2013.
Following these changes in our reporting period, the period July 1, 2013 to June 30, 2014 is referred to as the 2014 fiscal year.
The period January 1, 2013 to June 30, 2013 is referred to as the 2013 fiscal year. January 1, 2012 to December 31, 2012 is referred to as the 2012 fiscal year. As a result of the fiscal year change, please note that this is the
third quarter report for the fiscal year ending June 30, 2014.
7
Use of Estimates
The preparation of the Companys unaudited condensed consolidated financial statements in conformity with accounting principles generally
accepted in the United States requires the Companys management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the
unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. The Company bases its estimates and judgments on historical experience and on various other assumptions
and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more
experience is acquired, as additional information is obtained and as the Companys operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Companys unaudited condensed
consolidated financial statements.
Interim period results are not necessarily indicative of results of operations or cash flows for the
full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted.
Gas Gathering Systems and Equipment and Other Operating Assets
Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year estimated
useful life. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which
increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The Company did not capitalize any interest related to the construction of the Companys gas gathering systems and equipment
for the nine months ended March 31, 2014 or for the nine months ended March 31, 2013.
The contribution of the Companys
Haynesville Shale gas gathering and treating business to KinderHawk Field Services LLC (KinderHawk) on May 21, 2010 for a 50% membership interest and approximately $917 million in cash is accounted for in accordance with Financial Accounting
Standards Boards (FASB) Accounting Standards Codification (ASC) Subtopic 360-20,
Property, Plant and EquipmentReal Estate Sales
(ASC 360-20). Under the financing method, the historical cost of the Haynesville Shale gas gathering
system contributed to KinderHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated balance sheets in
Gas gathering systems and equipment
and depreciated over the remaining useful life of
the assets. Contributions to KinderHawk from the Company and the joint venture partner were recorded as increases in
Gas gathering systems and equipment
on the unaudited condensed consolidated balance sheets. On July 1, 2011,
the Company transferred its remaining 50% membership interest in KinderHawk to KM Gathering LLC (KM Gathering).
On July 1, 2011, the
Company transferred a 25% interest in BHP Billiton Petroleum (Eagle Ford Gathering) LLC (BHP Eagle Ford Gathering), formerly known as EagleHawk Field Services LLC, to KM Eagle Gathering LLC (Eagle Gathering). The BHP Eagle Ford Gathering transaction
is accounted for in accordance with ASC 360-20. Under the financing method, the historical cost of the Eagle Ford Shale gas gathering systems contributed to BHP Eagle Ford Gathering is carried at the full historical basis of the assets on the
unaudited condensed consolidated balance sheets in
Gas gathering systems and equipment
and depreciated over the remaining useful life of the assets. Contributions to BHP Eagle Ford Gathering from the Company and the joint venture
partner are recorded as increases in
Gas gathering systems and equipment
on the unaudited condensed consolidated balance sheets.
Gas gathering systems and equipment as of March 31, 2014 and June 30, 2013 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
2014
|
|
|
June 30,
2013
|
|
|
|
(In thousands)
|
|
Gas gathering systems and equipment
|
|
$
|
1,936,647
|
|
|
$
|
1,648,198
|
|
Less accumulated depreciation
|
|
|
(128,465
|
)
|
|
|
(88,714
|
)
|
|
|
|
|
|
|
|
|
|
Net gas gathering systems and equipment
|
|
$
|
1,808,182
|
|
|
$
|
1,559,484
|
|
|
|
|
|
|
|
|
|
|
8
(1)
|
Under the financing method, the historical cost of the Haynesville Shale gas gathering system contributed to KinderHawk is carried at the full historical basis of the assets on the unaudited condensed consolidated
balance sheets in
Gas gathering systems and equipment
and depreciated over the remaining useful life of the assets. As of March 31, 2014 and June 30, 2013, the table above includes approximately $387.1 million and $398.1
million, respectively, attributed to the net carrying value of the assets contributed to KinderHawk.
|
(2)
|
Under the financing method, the historical cost of the Eagle Ford Shale gas gathering systems contributed to BHP Eagle Ford Gathering is carried at the full historical basis of the assets on the unaudited condensed
consolidated balance sheets in
Gas gathering systems and equipment
and depreciated over the remaining useful life of the assets. As of March 31, 2014 and June 30, 2013, the table above includes approximately $1,129.1
million and $909.4 million, respectively, attributed to the net carrying value of the assets contributed to BHP Eagle Ford Gathering.
|
Other operating property and equipment are recorded at cost. Depreciation is calculated using the straight-line method over the following
estimated useful lives: automobiles, leasehold improvements, furniture and equipment, five years or lesser of lease term; rental equipment and capitalized software implementation costs, seven years; and computers, three years. Upon disposition, the
cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures, which increase the life of an asset, are
capitalized and depreciated over the estimated remaining useful life of the asset.
The Company reviews its gas gathering systems and
equipment and other operating assets in accordance with ASC 360,
Property, Plant, and Equipment
(ASC 360). ASC 360 requires the Company to evaluate gas gathering systems and equipment and other operating assets as events occur or
circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference
between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its gas gathering systems and equipment and other operating assets at each reporting period to determine whether events and
circumstances warrant a revision to the remaining depreciation periods.
Payable on Financing Arrangements
The contribution of the Companys Haynesville Shale gas gathering and treating business to KinderHawk on May 21, 2010, for a 50%
membership interest and approximately $917 million in cash is accounted for in accordance with ASC 360-20. Due to the gathering agreement entered into with the formation of KinderHawk, which constitutes extended continuing involvement under ASC
360-20, it has been determined that the contribution of the Companys Haynesville Shale gathering and treating system to form KinderHawk is accounted for as a failed sale of in substance real estate. Under the financing method for a failed sale
of in substance real estate, on May 21, 2010, the Company recorded a financing obligation on the unaudited condensed consolidated balance sheets in
Payable on financing arrangements,
in the amount of approximately $917
million. Reductions to the obligation and the non-cash interest on the financing obligation are tied to the gathering and treating services, as the Company delivers natural gas through the Haynesville Shale gathering and treating system. Interest
and principal are determined based upon the allocable income to the joint venture partner, and interest is limited up to an amount that is calculated based upon the Companys weighted average cost of debt as of the date of the transaction.
Allocable income in excess of the calculated value is reflected as reductions of principal. Interest is recorded in
Interest expense and other
on the unaudited condensed consolidated statements of operations. On July 1, 2011,
the Company transferred its remaining 50% membership interest in KinderHawk to KM Gathering. As a result of the transfer on July 1, 2011, the Company recorded an increase in its financing obligation associated with KinderHawk of approximately
$743 million.
The Companys transfer of a 25% interest in BHP Eagle Ford Gathering on July 1, 2011, to Eagle Gathering is
accounted for in accordance with ASC 360-20. Due to the gathering agreements which constitute extended continuing involvement under ASC 360-20, it has been determined that the transfer of the Companys Eagle Ford Shale gathering and treating
systems to BHP Eagle Ford Gathering is accounted for as a failed sale of in substance real estate. Under the financing method for a failed sale of in substance real estate, on July 1, 2011, the Company recorded a financing obligation on the
unaudited condensed consolidated balance sheets in
Payable on financing arrangements,
in the amount of approximately $93 million. Reductions to the obligation and the non-cash interest on the financing obligation are tied to the
gathering and treating services, as the Company delivers natural gas through the Eagle Ford Shale gathering and treating systems. Interest and principal are determined based upon the allocable income to the joint venture partner, and interest is
limited up to an amount that is calculated based upon the Companys weighted average cost of debt as of the date of the transaction. Allocable income in excess of the calculated value is reflected as reductions of principal.
9
The balance of the Companys financing obligations as of March 31, 2014 and
June 30, 2013, was approximately $1.9 billion and $1.9 billion, respectively, of which approximately $21.8 million and $20.9 million was classified as current for the respective periods.
Restricted Cash
In conjunction with the
termination of the BHP Eagle Ford Gathering Revolving Credit Agreement during 2011, BHP Eagle Ford Gathering began issuing cash calls in accordance with each partys membership interest to the Company and Kinder Morgan in order to fund Eagle
Ford Gatherings capital expenditures needs. Since BHP Eagle Ford Gatherings cash balances are restricted for the purpose of funding its capital program, the Company presented BHP Eagle Ford Gatherings cash of approximately $30.3
million and $30.4 million as
Restricted cash
at March 31, 2014 and June 30, 2013, respectively. Additionally, from time to time, the Company may be requested to escrow certain disputed royalty funds, and as a result, the
Company presented cash of approximately $6.2 million and $4.8 million as
Restricted Cash
at March 31, 2014 and June 30, 2013, respectively.
Marketing Revenue and Expense
The
Company engages, from time to time, in marketing operations when this meets the needs of the business. When the company engages in Marketing operations, a subsidiary of the Company purchases and sells third party natural gas produced from wells
which the Company and third parties operate. The revenues and expenses related to these marketing activities are reported on a gross basis as part of operating revenues and operating expenses when a sale arises. Marketing revenues are recorded at
the time natural gas is physically delivered to third parties at a fixed or index price. Marketing expenses attributable to gas purchases are recorded as the subsidiary of the Company takes physical title to natural gas and transports the purchased
volumes to the point of sale.
Midstream Revenues
Revenues from the Companys midstream operations are derived from providing gathering and treating services for the Company and other
owners in wells which the Company and third parties operate. Revenues are recognized when services are provided at a fixed or determinable price; collectability is reasonably assured and evidenced by a contract. The Companys midstream
operation does not take title to the natural gas for which services are provided, with the exception of imbalances that are monthly cash settled. The imbalances are recorded using published natural gas market prices.
The Companys transfer of a 25% interest in BHP Eagle Ford Gathering on July 1, 2011, to Eagle Gathering is accounted for in
accordance with ASC 360-20. Under the financing method for a failed sale of in substance real estate, the Company records BHP Eagle Ford Gatherings revenues, net of eliminations for intercompany amounts associated with gathering and treating
services provided to the Company, on the unaudited condensed consolidated statements of operations in
Midstream revenues.
Goodwill
We account for goodwill in accordance with ASC 350,
IntangiblesGoodwill and Other
(ASC 350). Goodwill represents the
excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350 requires that intangible assets with indefinite lives, including goodwill, be evaluated on an
annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting
units.
In September 2011, the Financial Accounting Standards Board issued ASU No. 2011-08,
Testing Goodwill for Impairment
(ASU 2011-08) to simplify how companies test goodwill for impairment. ASU 2011-08 simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the
conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying amount. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying
amount, then the entity does not have to perform the two-step impairment test. However, if that same conclusion is not reached, the company is required to perform the first step of the two-step impairment test. ASU 2011-08 also allows a company to
bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test. The first step is to compare the fair value of a reporting unit with its carrying value, including goodwill. If the fair value of a
reporting unit is less than its carrying value, then the second step of the test must be performed to measure the amount of the impairment loss, if any.
10
We perform our goodwill test annually during the quarter ending June 30 or more often if
circumstances require. The last goodwill test was conducted during the 2013 fiscal year for inclusion in the
Transition Report to Security Holders dated June 30, 2013
. The test results at that time did not indicate impairment. Our
qualitative assessment included an evaluation of factors such as macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, as well as other relevant events and circumstances that affect the fair value
or carrying amount. Based on this qualitative assessment, there were no impairment indicators that would indicate that it is more likely than not that the fair value of the Companys oil and gas reporting unit is less than its carrying amount.
As such, we did not perform the two-step goodwill impairment test during the six months ended June 30, 2013. In previous years, our goodwill impairment reviews consisted of the two-step process. The first step is to determine the fair value of
our reporting unit and compare it to the carrying value of the related net assets. Fair value is determined based on our estimates of market values. If this fair value exceeds the carrying value no further analysis or goodwill write-down is
required. The second step is required if the fair value of the reporting unit is less than the book value of the net assets. In this step, the implied fair value of the reporting unit is allocated to all the underlying assets and liabilities,
including both recognized and unrecognized tangible and intangible assets, based on their fair values. If necessary, goodwill is then written-down to its implied fair value. If the fair value of the reporting unit is less than the book value
(including goodwill), then goodwill is reduced to its implied fair value and the amount of the write down is charged against earnings. The assumptions we used in calculating our reporting unit fair values at the time of the test in prior years
include our market capitalization and discounted future cash flows based on estimated reserves and production, future costs and future oil and natural gas prices. Material adverse changes to any of the factors considered could lead to an impairment
of all or a portion of our goodwill in future periods.
Other Intangible Assets
The Company treats the costs associated with acquired transportation contracts as intangible assets which will be amortized over the life of
the extended agreement. The initial amount recorded represents the fair value of the contract at the time of acquisition, which is amortized under the straight-line method over the life of the contract. Any unamortized balance of the Companys
intangible assets will be subject to impairment testing pursuant to the
Impairment or Disposal of Long-Lived Assets
Subsections of ASC Subtopic 360-10 (ASC 360-10). The Company reviews its intangible assets for potential impairment whenever
events or changes in circumstances indicate that an other-than-temporary decline in the value of the investment has occurred.
There was no amortization expense during the nine months ended March 31, 2014. Amortization expense was $5.5 million for the nine months
ended March 31, 2013, and was included in
Gathering, transportation and other
on the unaudited condensed consolidated statements of operations.
During 2012, one acquired transportation contract (the Kaiser contract) for gas export from the Haynesville field reached a point at which the
Company had the option to cancel or extend the contract at its sole discretion. Due to the changes in the gas market since the time of acquisition and the availability of alternative transportation routes, the decision was made not to extend this
contract. As a result, a change in circumstances was noted and the remaining net book value of approximately $67.2 million associated with the Kaiser contract was impaired during the period ending December 31, 2012.
Intangible assets subject to amortization at March 31, 2014 and March 31, 2013 are as follows:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
March 31, 2014
|
|
|
Nine Months Ended
March 31, 2013
|
|
|
|
(In thousands)
|
|
Transportation contracts gross book value at June 30
|
|
$
|
|
|
|
$
|
105,108
|
|
Less accumulated amortization at June 30
|
|
|
|
|
|
|
(32,345
|
)
|
Less amortization of nine months to March 31
|
|
|
|
|
|
|
(5,526
|
)
|
Less Impairment of Kaiser contract
|
|
|
|
|
|
|
(67,237
|
)
|
|
|
|
|
|
|
|
|
|
Net transportation contracts at March 31
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
11
Recently Issued Accounting Pronouncements
In February 2013, the FASB issued ASU 2013-04,
Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements
for Which the Total Amount of the Obligation Is Fixed at the Reporting Date
(ASU 2013-04). This guidance is intended to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability
arrangements for which the total amount of the obligation is fixed at the reporting date, excluding obligations accounted for under existing guidance. This guidance requires an entity to measure these obligations as a sum of the amount the reporting
entity agreed to pay and any additional amount the reporting entity expects to pay on behalf of its co-obligors. This guidance will be effective for fiscal years ending after December 15, 2014, and interim and annual periods thereafter, with
early adoption permitted. The Company is currently assessing the impact, if any, that ASU 2013-04 will have on its disclosures.
No other
pronouncements made during calendar year 2014 are anticipated to impact Petrohawk, during this current fiscal year.
2. OIL AND NATURAL GAS PROPERTIES
The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of
accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct
internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion exceed the discounted future net revenues of
proved oil and natural gas reserves net of deferred taxes, such excess capitalized costs are charged to expense. Full cost companies use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period
preceding the calculation date.
The Company assesses all items classified as unevaluated property on a periodic basis for possible
impairment or reduction in value. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill;
remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors
indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and the full cost ceiling test
limitation.
At March 31, 2014, the ceiling test value of the Companys reserves was calculated based on the first day average
of the 12-months ended March 31, 2014, of the West Texas Intermediate (WTI) spot price of $98.60 per barrel or was calculated based equally on the respective first day average of the 12-months ended March 31, 2014, of the WTI spot price of
$98.60 per barrel and the Light Louisiana Sweet (LLS) differential spot price of $6.55 per barrel, depending on location and adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of
the 12-months ended March 31, 2014, of the Henry Hub price of $3.99 per million British thermal units (Mmbtu), adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the
Companys net book value of oil and natural gas properties at March 31, 2014 did not exceed the ceiling amount. Changes in production rates, levels of reserves, future development costs, and other factors will determine the Companys
actual ceiling test calculation and impairment analyses in future periods.
At June 30, 2013, the ceiling test value of the
Companys reserves was calculated based on the first day average of the 12-months ended June 30, 2013, of the West Texas Intermediate (WTI) spot price of $91.60 per barrel or was calculated based equally on the respective first day average
of the 12-months ended June 30, 2013, of the WTI spot price of $91.60 per barrel and the Light Louisiana Sweet (LLS) differential spot price of $16.95 per barrel, depending on location and adjusted by lease or field for quality, transportation
fees, and regional price differentials, and the first day average of the 12-months ended June 30, 2013 of the Henry Hub price of $3.47 per million British thermal units (Mmbtu), adjusted by lease or field for energy content, transportation
fees, and regional price differentials. Using these prices, the Companys net book value of oil and natural gas properties at June 30, 2013 did not exceed the ceiling amount. Changes in production rates, levels of reserves, future
development costs, and other factors will determine the Companys actual ceiling test calculation and impairment analyses in future periods.
12
3. LONG-TERM DEBT
On January 2, 2014, the Company issued a formal notice of redemption to noteholders of its 10.5% Senior Notes due 2014 and 7.875% Senior
Notes due 2015. All outstanding Senior Notes due 2014 and 2015 were redeemed on February 3, 2014 at the applicable call prices. The total aggregate principal value of the notes redeemed was $1.4 billion US Dollars.
|
|
|
|
|
|
|
Redemption of Senior
Notes
|
|
|
|
(in thousands)
|
|
Redemption Proceeds (including call premium)
|
|
$
|
(1,404,995
|
)
|
Add Principal
|
|
|
1,389,251
|
|
Less Unamortized Premium/Discount
|
|
|
(6,151
|
)
|
Less Unamortized Debt Issuance Costs
|
|
|
(4,051
|
)
|
|
|
|
|
|
Loss on Redemption of Senior Notes
|
|
$
|
(25,946
|
)
|
|
|
|
|
|
Long-term debt as of March 31, 2014 and June 30, 2013, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
2014
|
|
|
June 30,
2013
|
|
|
|
(In thousands)
|
|
6.25% $600 million senior notes
|
|
$
|
600,000
|
|
|
$
|
600,000
|
|
7.25% $1.2 billion senior notes
(1)
|
|
|
1,229,811
|
|
|
|
1,230,501
|
|
10.5% $600 million senior notes
(2)(3)
|
|
|
|
|
|
|
576,654
|
|
7.875% $800 million senior notes
(3)
|
|
|
|
|
|
|
799,611
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,829,811
|
|
|
$
|
3,206,766
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Amount includes a $4.8 million and $5.5 million premium at March 31, 2014 and June 30, 2013, respectively, recorded by the Company in conjunction with the issuance of the additional $400 million principal
amount. See
7.25% Senior Notes
below for more details.
|
(2)
|
Amount includes a $13.0 million discount at June 30, 2013, which was recorded by the Company in conjunction with the issuance of the 10.5% senior notes due 2014. See
10.5% Senior Notes
below for
more details.
|
(3)
|
Both Senior Notes were called for redemption on January 2, 2014 and settled on February 3, 2014.
|
6.25% Senior Notes
On May 20, 2011,
the Company completed a private placement offering to eligible purchasers of an aggregate principal amount of $600 million of its 6.25% senior notes due 2019 (the 2019 Notes). The 2019 Notes were issued under and are governed by an indenture dated
May 20, 2011, between the Company, U.S. Bank Trust National Association, as trustee, and the Companys subsidiaries named therein as guarantors (the 2019 Indenture). The 2019 Notes were sold to investors at 100% of the aggregate principal
amount of the 2019 Notes. The net proceeds from the sale of the 2019 Notes were approximately $589 million (after deducting offering fees and expenses). The proceeds were used to repay borrowings outstanding under the Companys senior revolving
credit facility and for working capital for general corporate purposes.
The 2019 Notes bear interest at a rate of 6.25% per annum,
payable semi-annually on June 1 and December 1 of each year, commencing on December 1, 2011. The 2019 Notes will mature on June 1, 2019. The 2019 Notes are senior unsecured obligations of the Company and rank equally with all of
its current and future senior indebtedness. The 2019 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Companys subsidiaries, with the exception of two subsidiaries (Proliq, Inc. and BHP
Eagle Ford Gathering, LLC), as discussed in Note 9,
BHP Eagle Ford Gathering (formerly EagleHawk Field Services).
Petrohawk Energy Corporation, the issuer of the 2019 Notes, has no material independent assets or operations apart
from the assets and operations of its subsidiaries.
13
On or prior to June 1, 2014, the Company may redeem up to 35% of the aggregate principal
amount of the 2019 Notes with the net cash proceeds of certain equity offerings at a redemption price of 106.25% of the principal amount, plus accrued and unpaid interest to the redemption date; provided that at least 65% in aggregate principal of
the 2019 Notes originally issued under the 2019 Indenture remain outstanding immediately after the redemption. In addition, on or prior to June 1, 2015, the Company may redeem all or part of the 2019 Notes at a redemption price equal to the
principal amount, plus accrued and unpaid interest, plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at June 1, 2015 plus (ii) any required
interest payments due on such note through June 1, 2015 (except for currently accrued and unpaid interest), computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis
(assuming a 360-day year consisting of twelve 30-day months), over (b) the principal amount of such Note.
On or after June 1,
2015, the Company may redeem all or a part of the 2019 Notes at any time or from time to time, at the redemption prices (expressed as percentages of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the
applicable redemption date, if redeemed during the 12-month period beginning on June 1 of the years indicated below:
|
|
|
|
|
Year
|
|
Percentage
|
|
2015
|
|
|
103.125
|
|
2016
|
|
|
101.563
|
|
2017
|
|
|
100.000
|
|
The Company is required to offer to repurchase the 2019 Notes at a purchase price of 101% of the principal
amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined in the 2019 Indenture that is followed by a decline within 90 days in the ratings of the 2019 Notes published by either
Moodys Investor Service, Inc. (Moodys) or Standard & Poors Rating Services (S&P). The Companys credit rating did not decline in the allotted period of time after the change of control with the closing of the BHP
merger. As a result, no such offer was made. The 2019 Indenture contains covenants that, among other things, restrict or limit the ability of the Company and its subsidiaries to: borrow money; pay dividends on stock; purchase or redeem stock or
subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; and merge with or into other companies or transfer all or substantially all of the Companys assets. However, during the fourth
quarter of 2011, an Investment Grade Rating Event (as defined in the 2019 Indenture) occurred that resulted in certain covenants in the 2019 Indenture, including covenants relating to incurrence of indebtedness, restricted payments, asset sales and
affiliate transactions, being terminated.
7.25% Senior Notes
On August 17, 2010, the Company completed a private placement offering to eligible purchasers of an aggregate principal amount of $825
million of its 7.25% senior notes due 2018 (the initial 2018 Notes) at a purchase price of 100% of the principal amount of the initial 2018 Notes. The initial 2018 Notes were issued under and are governed by an indenture dated August 17, 2010,
between the Company, U.S. Bank Trust National Association, as trustee, and the Companys subsidiaries named therein as guarantors (the 2018 Indenture). The Company applied the net proceeds from the sale of the initial 2018 Notes to redeem its
$775 million 9.125% senior notes due 2013.
On January 31, 2011, the Company completed the issuance of an additional $400 million
aggregate principal amount of its 7.25% senior notes due 2018 (the additional 2018 Notes) in a private placement to eligible purchasers. The additional 2018 Notes are issued under the same Indenture and are part of the same series as the initial
2018 Notes. The additional 2018 Notes together with the initial 2018 Notes are collectively referred to as the 2018 Notes.
The additional
2018 Notes were sold to Barclays Capital Inc. at 101.875% of the aggregate principal amount of the additional 2018 Notes plus accrued interest. The net proceeds from the sale of the additional 2018 Notes were approximately $400.5 million (after
deducting offering fees and expenses). A portion of the proceeds of the additional 2018 Notes were utilized to redeem all of the Companys outstanding $275 million 7.125% senior notes due 2012.
Interest on the 2018 Notes is payable on February 15 and August 15 of each year, beginning on February 15, 2011. Interest on
the 2018 Notes accrued from August 17, 2010, the original issuance date of the series. The 2018 Notes will mature on August 15, 2018. The 2018 Notes are senior unsecured obligations of the Company and rank equally with all of the
Companys current and future senior indebtedness. The 2018 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Companys subsidiaries, with the exception of two subsidiaries (Proliq,
Inc. and BHP Eagle Ford Gathering, LLC), as discussed in Note 9,
BHP Eagle Ford Gathering (formerly EagleHawk Field Services).
Petrohawk Energy Corporation, the issuer of the 2018 Notes, has no material independent assets or
operations apart from the assets and operations of its subsidiaries.
14
On or prior to August 15, 2013, the Company may redeem up to 35% of the aggregate principal
amount of the 2018 Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.25% of the principal amount, plus accrued and unpaid interest to the redemption date; provided that at least 65% in aggregate principal
amount of the 2018 Notes originally issued under the 2018 Indenture remain outstanding immediately after the redemption. In addition, at any time prior to August 15, 2014, the Company may redeem some or all of the 2018 Notes for the principal
amount, plus accrued and unpaid interest, plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at August 15, 2014, (ii) any required interest
payments due on the notes (except for currently accrued and unpaid interest), computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal
amount of such note.
On or after August 15, 2014, the Company may redeem all or part of the 2018 Notes at any time or from time to
time at the redemption prices (expressed as a percentage of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning
August 15 of the years indicated below:
|
|
|
|
|
Year
|
|
Percentage
|
|
2014
|
|
|
103.625
|
|
2015
|
|
|
101.813
|
|
2016 and thereafter
|
|
|
100.000
|
|
The Company is required to offer to repurchase the 2018 Notes at a purchase price of 101% of the principal
amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined in the 2018 Indenture that is followed by a decline within 90 days in the ratings of the 2018 Notes published by either
Moodys or S&P. The Companys credit rating did not decline in the allotted period of time after the change of control with the closing of the BHP merger. As a result, no such offer was made. The 2018 Indenture contains covenants that,
among other things, restrict or limit the ability of the Company and its subsidiaries to: borrow money; pay dividends on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with
affiliates; sell assets; and merge with or into other companies or transfer all or substantially all of the Companys assets. However, during the fourth quarter of 2011, an Investment Grade Rating Event (as defined in the 2018 Indenture)
occurred that resulted in certain covenants in the 2018 Indenture, including covenants relating to incurrence of indebtedness, restricted payments, asset sales and affiliate transactions, being terminated.
In conjunction with the issuance of the additional 2018 Notes, the Company recorded a premium of $7.5 million to be amortized over the
remaining life of the notes utilizing the effective interest rate method. The remaining unamortized premium was $4.8 million and $5.5 million at March 31, 2014 and June 30, 2013, respectively.
10.5% Senior Notes
On January 27,
2009, the Company completed a private placement offering to eligible purchasers of an aggregate principal amount of $600 million of its 10.5% senior notes due August 1, 2014 (the 2014 Notes). The 2014 notes were issued under and were governed
by an indenture dated January 27, 2009, between the Company, U.S. Bank Trust National Association, as trustee, and the Companys subsidiaries named therein as guarantors (the 2014 Indenture).
These Notes were called for redemption and settled in full on February 3, 2014 at the redemption price of 100.000%.
7.875% Senior Notes
On May 13, 2008
and June 19, 2008, the Company issued $500 million principal amount and $300 million principal amount, respectively, of its 7.875% senior notes due 2015 (the 2015 Notes) pursuant to an indenture (the 2015 Indenture). The 2015 Notes were issued
under and were governed by an indenture dated May 13, 2008, between the Company, U.S. Bank Trust National Association, as trustee, and the Companys subsidiaries named therein as guarantors.
These Notes were called for redemption and settled in full on February 3, 2014 at the redemption price of 101.969%.
15
Debt Issuance Costs
The Company capitalizes certain direct costs associated with the issuance of long-term debt. At March 31, 2014 and June 30, 2013, the
Company had approximately $20.9 million and $31.5 million, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt.
4. FAIR VALUE MEASUREMENTS
Pursuant to
ASC 820,
Fair Value Measurements and Disclosures
(ASC 820) the Companys determination of fair value incorporated not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on
the Companys unaudited condensed consolidated balance sheets, but also the impact of the Companys nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilized market data or assumptions that market participants would use in pricing the asset or liability, including
assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classified fair value balances based on the observability of
those inputs.
There were no financial assets or liabilities that were accounted for at fair value as of March 31, 2014 or
June 30, 2013. As required by ASC 820, a financial instruments level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. If any financial assets or liabilities are
acquired that would be accounted for at fair value, the Companys assessment of the significance of a particular input to the fair value measurement would require judgment, and may affect the valuation of fair value assets and liabilities and
their placement within the fair value hierarchy levels.
The following disclosure of the estimated fair value of financial instruments is
made in accordance with the requirements of ASC 825,
Financial Instruments
. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and
cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The following table presents the estimated fair values of the
Companys fixed interest rate, long-term debt instruments as of March 31, 2014 and June 30, 2013 (
excluding
premiums and discounts
):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2014
|
|
|
June 30, 2013
|
|
Debt
|
|
Carrying
Amount
|
|
|
Estimated
Fair Value
|
|
|
Carrying
Amount
|
|
|
Estimated
Fair Value
|
|
|
|
(In thousands)
|
|
6.25% $600 million senior notes
|
|
$
|
600,000
|
|
|
$
|
654,750
|
|
|
$
|
600,000
|
|
|
$
|
657,948
|
|
7.25% $1.2 billion senior notes
|
|
|
1,225,000
|
|
|
|
1,295,805
|
|
|
|
1,225,000
|
|
|
|
1,306,463
|
|
7.875% $800 million senior notes
|
|
|
|
|
|
|
|
|
|
|
799,611
|
|
|
|
816,720
|
|
10.5% $600 million senior notes
|
|
|
|
|
|
|
|
|
|
|
589,640
|
|
|
|
631,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Debt
|
|
$
|
1,825,000
|
|
|
$
|
1,950,555
|
|
|
$
|
3,214,251
|
|
|
$
|
3,412,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair values of the Companys fixed interest debt instruments were calculated using quoted market
prices based on trades of such debt as of March 31, 2014 and June 30, 2013, respectively.
16
5. ASSET RETIREMENT OBLIGATION
The Company records an asset retirement obligation (ARO) when the total depth of a drilled well is reached and the Company can reasonably
estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. For gas gathering systems and equipment, the Company records an ARO when the system is placed in service and the Company can
reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes a portion of the cost in
Oil and natural gas properties
or
Gas gathering systems and equipment
during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in
Depletion,
depreciation and amortization
expense in the unaudited condensed consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.
The Company recorded the following activity related to the ARO liability for the nine months ended March 31, 2014 (in thousands):
|
|
|
|
|
Liability for asset retirement obligation as of June 30, 2013
|
|
$
|
156,083
|
|
Additions
|
|
|
6,565
|
|
Accretion expense
|
|
|
1,980
|
|
Revisions in estimated cash flows and other
|
|
|
|
|
|
|
|
|
|
Liability for asset retirement obligation as of September 30, 2013
|
|
$
|
164,628
|
|
Additions
|
|
|
6,688
|
|
Accretion expense
|
|
|
2,086
|
|
Revisions in estimated cash flows and other
|
|
|
|
|
|
|
|
|
|
Liability for asset retirement obligation as of December 31, 2013
|
|
$
|
173,402
|
|
|
|
|
|
|
Additions
|
|
|
14,222
|
|
Accretion expense
|
|
|
2,167
|
|
Revisions in estimated cash flows and other
|
|
|
(2,190
|
)
|
|
|
|
|
|
Liability for asset retirement obligation as of March 31, 2014
|
|
$
|
187,601
|
|
|
|
|
|
|
17
6. COMMITMENTS AND CONTINGENCIES
Commitments
The Company leases corporate
office space in Houston, Texas and Tulsa, Oklahoma as well as a number of other field office locations. In addition, the Company has lease commitments related to certain vehicles, machinery and equipment under long-term operating leases.
As of March 31, 2014, the Company had the following commitments:
|
|
|
|
|
|
|
|
|
|
|
Total Obligation
Amount
|
|
|
Years
Remaining
|
|
|
|
(in thousands)
|
|
|
|
|
Gathering and transportation commitments
|
|
$
|
3,101,296
|
|
|
|
15
|
|
Drilling rig commitments
|
|
|
481,869
|
|
|
|
6
|
|
Non-cancelable operating leases
|
|
|
16,268
|
|
|
|
10
|
|
Pipeline and well equipment obligations
|
|
|
22,100
|
|
|
|
1
|
|
Various contractual commitments (including, among other things, rental equipment obligations, obtaining and processing seismic
data)
|
|
|
105,600
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Total commitments
|
|
$
|
3,727,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As part of the KinderHawk transaction, one of the Companys gathering and transportation commitments is
the obligation to deliver to KinderHawk agreed upon minimum annual quantities of natural gas from the Companys operated wells producing from the Haynesville and Lower Bossier Shales, within specified acreage in Northwest Louisiana through May
2015. In addition, the Company pays an annual fee to KinderHawk if such minimum annual quantities are not delivered. The Companys obligation to deliver minimum annual quantities of natural gas to KinderHawk through May 2015 remains in effect
following the transfer of the Companys remaining 50% membership interest in KinderHawk on July 1, 2011. The minimum annual quantities per contract year are as follows:
|
|
|
|
|
Contract Year
|
|
Minimum
Annual
Quantity (Bcf)
|
|
Year 1 (partial)2010
|
|
|
81.090
|
|
Year 22011
|
|
|
152.899
|
|
Year 32012
|
|
|
238.595
|
|
Year 42013
|
|
|
324.047
|
|
Year 52014
|
|
|
368.614
|
|
Year 6 (partial)2015
|
|
|
143.066
|
|
These volumes represent 50% of the Companys anticipated production from the specified acreage at the
time the Company entered into the contract.
The Company pays KinderHawk negotiated gathering and treating fees, subject to an annual
inflation adjustment factor. The gathering fee at the time the Company entered into the contract was equal to $0.34 per Mcf of natural gas delivered at KinderHawks receipt points. The treating fee is charged for gas delivered containing more
than 2% by volume of carbon dioxide. For gas delivered containing between 2% and 5.5% carbon dioxide, the treating fee is between $0.030 and $0.345 per Mcf, and for gas containing over 5.5% carbon dioxide, the treating fee starts at $0.365 per Mcf
and increases on a scale of $0.09 per Mcf for each additional 1% of carbon dioxide content. In the event that annual natural gas deliveries are ever less than the minimum annual quantity per contract year set forth in the table above, the
Companys fee obligation would be determined by subtracting the quantity delivered from the minimum annual quantity for the applicable contract year and multiplying the positive difference by the sum of the gathering fee in effect on the last
day of such year plus the average monthly treating fees for such year. For example, if the quantity of natural gas delivered in 2013 were 50 Bcf less than the minimum annual quantity for such year and the year-end gathering fee was $0.34 per Mcf and
the average treating fee for the period was $0.345 per Mcf, the fee would be $34.3 million. An annual deficiency payment of $56.3 million related to not delivering the minimum quantities required by the KinderHawk contract with Kinder Morgan has
been made in February 2014. This payment covers the calendar year ending December 31, 2013.
18
As previously discussed, the Company has certain amounts associated with the sale of its
interests in KinderHawk and BHP Eagle Ford Gathering recorded as financing obligations in the unaudited condensed consolidated balance sheets, which are not reflected in the amounts shown in the table above. The balance of the Companys
financing obligations as of March 31, 2014 and June 30, 2013, was approximately $1.9 billion and $1.9 billion, respectively, of which approximately $21.8 million and $20.9 million was classified as current for the respective periods.
Contingencies
From time to time, the
Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued based on the Companys best estimate of the probable loss. While the outcome and
impact of currently pending legal proceedings cannot be determined, the Companys management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on
the Companys consolidated operating results, financial position or cash flows.
7. STOCKHOLDERS EQUITY
As discussed in Note 1,
Financial Statement Presentation,
pursuant to the terms of the Merger Agreement on August 20,
2011, Purchaser accepted for payment all Shares of the Companys common stock, approximately 293.9 million shares, representing approximately 97.4% of the total outstanding shares and on August 25, 2011, Purchaser completed a
short-form merger under Delaware law of Purchaser with and into the Company, with the Company being the surviving corporation. At the effective time of such merger, each share issued and outstanding immediately prior to the effective time of such
merger ceased to be issued and outstanding and were converted into the right to receive an amount in cash equal to the Offer Price, without interest. As a result of such merger, the Company was authorized to issue 100 shares with par value of $0.001
per share all of which are owned by Parent.
19
8. ADDITIONAL FINANCIAL STATEMENT INFORMATION
Certain balance sheet amounts are comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31,
2014
|
|
|
June 30,
2013
|
|
|
|
(In thousands)
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues
|
|
$
|
619,718
|
|
|
$
|
248,631
|
|
Joint interest accounts
|
|
|
207,625
|
|
|
|
221,573
|
|
Income and other taxes receivable
|
|
|
32,168
|
|
|
|
12,055
|
|
Other
|
|
|
495
|
|
|
|
40,998
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
860,006
|
|
|
$
|
523,257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaids and other
|
|
$
|
34,366
|
|
|
$
|
33,372
|
|
|
|
|
Accounts payable and accrued liabilities:
|
|
|
|
|
|
|
|
|
Trade payables
|
|
$
|
295,627
|
|
|
$
|
167,023
|
|
Revenues and royalties payable
|
|
|
212,822
|
|
|
|
214,517
|
|
Accrued oil and natural gas capital costs
|
|
|
974,789
|
|
|
|
726,179
|
|
Accrued midstream capital costs
|
|
|
147,567
|
|
|
|
125,558
|
|
Accrued interest expense
|
|
|
6,156
|
|
|
|
67,721
|
|
Taxes other than income
|
|
|
141,049
|
|
|
|
28,005
|
|
Accrued employee compensation
|
|
|
574
|
|
|
|
3,365
|
|
Income taxes payable
|
|
|
|
|
|
|
(1,485
|
)
|
Related party payable
|
|
|
310,341
|
|
|
|
31,510
|
|
Other
|
|
|
17,504
|
|
|
|
196,422
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,106,429
|
|
|
$
|
1,558,815
|
|
|
|
|
|
|
|
|
|
|
9. BHP EAGLE FORD GATHERING
(
FORMERLY EAGLEHAWK FIELD SERVICES
)
On July 1, 2011, the Company along with its subsidiaries BHP Billiton Petroleum (Tx Gathering) LLC ( BHP Texas Gathering)
(formerly
Hawk Field Services)
and BHP Billiton Petroleum (Eagle Ford Gathering) LLC (BHP Eagle Ford Gathering)
(formerly EagleHawk Field Services, LLC)
, closed previously announced transactions with KM Eagle Ford Gathering LLC, an affiliate of
Kinder Morgan Energy Partners, including the transfer by BHP Texas Gathering of a 25% interest in Eagle Ford Gathering to KM Eagle Ford Gathering LLC in exchange for cash consideration of approximately $93 million.
BHP Eagle Ford Gathering, which is managed by BHP Texas Gathering, owns and operates the gathering and treating assets and business serving
the Companys Hawkville and Black Hawk Fields in the Eagle Ford Shale. The Company has dedicated its production from its Eagle Ford Shale leases pursuant to gathering and treating agreements with BHP Eagle Ford Gathering.
BHP Eagle Ford Gathering is accounted for as a failed sale of in substance real estate under the provisions of ASC 360-20. ASC 360-20
establishes standards for recognition of profit on all real estate sales transactions other than retail land sales, without regard to the nature of the sellers business. In making the determination as to whether a transaction qualifies, in
substance, as a sale of real estate, the nature of the entire real estate being sold is considered, including the land plus the property improvements and the integral equipment. The Eagle Ford Shale gathering and treating systems consist of right of
ways, pipelines and processing facilities. We have concluded that the gathering agreements constitute extended continuing involvement under ASC 360-20, and have therefore determined that the transfer of the Companys Eagle Ford Shale gathering
and treating systems to BHP Eagle Ford Gathering should be accounted for as a failed sale of in substance real estate.
20
The following table presents statement of operations information for BHP Eagle Ford Gathering for
the nine months ended March 31, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
March 31, 2014
|
|
|
Nine Months Ended
March 31, 2013
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
Midstream
|
|
$
|
39,909
|
|
|
$
|
39,209
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
39,909
|
|
|
|
39,209
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Taxes other than income
|
|
|
5,499
|
|
|
|
3,509
|
|
Gathering, transportation and other
|
|
|
36,537
|
|
|
|
27,366
|
|
General and administrative
|
|
|
805
|
|
|
|
1,433
|
|
Depletion, depreciation and amortization
|
|
|
24,442
|
|
|
|
15,839
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
67,283
|
|
|
|
48,147
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) from operations
|
|
|
(27,374
|
)
|
|
|
(8,938
|
)
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
Interest expense and other
|
|
|
(16,743
|
)
|
|
|
(11,539
|
)
|
|
|
|
|
|
|
|
|
|
Total other income (expenses)
|
|
|
(16,743
|
)
|
|
|
(11,539
|
)
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(44,117
|
)
|
|
|
(20,477
|
)
|
Income tax (expense) benefit
|
|
|
15,441
|
|
|
|
10,036
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss)
|
|
$
|
(28,676
|
)
|
|
$
|
(10,441
|
)
|
|
|
|
|
|
|
|
|
|
The following table presents balance sheet information for BHP Eagle Ford Gathering as of March 31, 2014
and June 30, 2013:
|
|
|
|
|
|
|
|
|
|
|
March 31,
2014
|
|
|
June 30,
2013
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
30,279
|
|
|
$
|
30,433
|
|
Accounts receivable
|
|
|
17,843
|
|
|
|
35,643
|
|
Prepaids and other
|
|
|
9,641
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
57,763
|
|
|
|
66,085
|
|
|
|
|
|
|
|
|
|
|
Other operating property and equipment:
|
|
|
|
|
|
|
|
|
Gas gathering systems and equipment
|
|
|
1,184,945
|
|
|
|
943,153
|
|
Other operating assets
|
|
|
2,575
|
|
|
|
954
|
|
|
|
|
|
|
|
|
|
|
Gross other operating property and equipment
|
|
|
1,187,520
|
|
|
|
944,107
|
|
Lessaccumulated depreciation
|
|
|
(58,587
|
)
|
|
|
(34,145
|
)
|
|
|
|
|
|
|
|
|
|
Net other operating property and equipment
|
|
|
1,128,933
|
|
|
|
909,962
|
|
|
|
|
|
|
|
|
|
|
Other noncurrent assets:
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
30,503
|
|
|
|
15,062
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,217,199
|
|
|
$
|
991,109
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
165,874
|
|
|
$
|
147,187
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
165,874
|
|
|
|
147,187
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
|
|
|
|
|
|
Other noncurrent liabilities
|
|
|
|
|
|
|
|
|
Payable to affiliate
|
|
|
389,625
|
|
|
|
294,858
|
|
Asset retirement obligations
|
|
|
13,008
|
|
|
|
13,008
|
|
Other
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
Additional paid-in capital
|
|
|
704,625
|
|
|
|
561,834
|
|
Accumulated deficit
|
|
|
(55,933
|
)
|
|
|
(25,778
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
648,692
|
|
|
|
536,056
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
1,217,199
|
|
|
$
|
991,109
|
|
|
|
|
|
|
|
|
|
|
21
The following table presents cash flow statement information for BHP Eagle Ford Gathering for the
nine months ended March 31, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended March 31,
|
|
|
|
2014
|
|
|
2013
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(28,676
|
)
|
|
$
|
(10,441
|
)
|
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
24,442
|
|
|
|
15,837
|
|
Income tax expense (benefit)
|
|
|
(15,441
|
)
|
|
|
(10,036
|
)
|
Other operating
|
|
|
(1,479
|
)
|
|
|
|
|
Change in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
17,809
|
|
|
|
(9,571
|
)
|
Prepaid and other
|
|
|
(9,641
|
)
|
|
|
131
|
|
Accounts payable and accrued liabilities
|
|
|
35,742
|
|
|
|
13,634
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by operating activities
|
|
|
22,756
|
|
|
|
(446
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Other operating property and equipment capital expenditures
|
|
|
(243,413
|
)
|
|
|
(227,605
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(243,413
|
)
|
|
|
(227,605
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Payable to affiliate
|
|
|
77,712
|
|
|
|
84,718
|
|
Net Contributions/Distributions from/to affiliate
|
|
|
142,791
|
|
|
|
112,371
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
220,503
|
|
|
|
197,089
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash:
|
|
|
|
|
|
|
|
|
Cash at beginning of period
|
|
|
30,433
|
|
|
|
55,327
|
|
|
|
|
|
|
|
|
|
|
Cash at end of period
|
|
$
|
30,279
|
|
|
$
|
24,365
|
|
|
|
|
|
|
|
|
|
|
As discussed in Note 3,
Long-Term Debt,
Petrohawk Energy Corporation has issued senior
notes that remain outstanding as of the date of this report. Petrohawk Energy Corporation has no material independent assets or operations and its senior notes have been guaranteed on an unconditional, joint and several basis, by all of its
wholly-owned subsidiaries that have assets or operations. BHP Eagle Ford Gathering
(formerly EagleHawk Field Services)
, which is not wholly-owned, and one of the Companys other subsidiaries, Proliq, Inc., are designated as unrestricted
subsidiaries for purposes of the Companys Senior Credit Agreement and indentures.
22
10. RELATED PARTY ARRANGEMENTS AND TRANSACTIONS
Effective January 1, 2013, the Company entered into the Management Services Agreement with BHP Billiton Limited, the parent company of
Petrohawk, for BHP Billiton Limited and its wholly owned subsidiaries to provide various personnel and payroll services as set forth in the agreement. Former employees of the Company transferred to become employees of BHP Billiton Limited, providing
services to the Company and the Company reimburses BHP Billiton Limited for the costs of these services. The total costs incurred under this agreement with BHP Billiton Limited for the nine months ended March 31, 2014, were $368.6 million. For
the nine months ended March 31, 2014 and for unsettled prior period activity, $89.8 million of cash payments were made between Petrohawk and BHP Billiton Limited, the parent company of Petrohawk. As a result, the total amount payable to BHP
Billiton Limited and its wholly owned subsidiaries as of March 31, 2014, is $310.3 million.
23
MANAGEMENTS NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our results of operations for the nine months ended March 31, 2014 and
2013 and should be read in conjunction with our unaudited condensed consolidated financial statements and the accompanying notes included in this report and with the consolidated financial statements, notes, and managements narrative analysis
included in our Transition Report to Security Holders dated June 30, 2013.
Statements in this discussion may be forward-looking.
These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.
Overview
We are an oil and natural gas
company engaged in the exploration, development and production of hydrocarbons predominantly from oil and gas shale properties located in the United States. As further discussed in Note 1
Financial Statement Presentation,
on
August 25, 2011, BHP Billiton Limited, a corporation organized under the laws of Victoria, Australia (BHP Billiton Limited), acquired 100% of our outstanding shares of common stock through the merger of a wholly owned subsidiary of BHP Billiton
Petroleum (North America) Inc., a Delaware corporation and wholly owned subsidiary of BHP Billiton Limited, with and into Petrohawk, with Petrohawk continuing as the surviving entity. At the date of this report, Petrohawk remains an indirect, wholly
owned subsidiary of BHP Billiton Limited (our parent).
Our financial results depend upon many factors, but are largely driven by the
volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire
properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline
capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.
Our cash flows are subject to a number of variables including our level of oil and natural gas production and commodity prices, as well as
various economic conditions that have historically affected the oil and natural gas industry. If natural gas prices remain at their current levels for a prolonged period of time or if oil and natural gas prices decline, our ability to fund our
capital expenditures, reduce debt, meet our financial obligations and become profitable may be materially impacted. Our primary sources of capital and liquidity, prior to the acquisition by BHP Billiton Limited, have been internally generated cash
flows from operations, proceeds from asset sales, capital market issuances of debt and equity, and availability under a former, now cancelled, Senior Credit Agreement. As of the date of acquisition by BHP Billiton Limited, our capital resources and
liquidity have been and will continue to be from internally generated cash flows from operations and funding from our Parent or otherwise arranged with third party lenders in accordance with the indentures governing our outstanding series of senior
notes.
The Company engages in acquisitions and divestitures from time to time to rationalize and further develop our portfolio of shale
assets. An agreement was completed on April 30 for the sale of approximately 37,000 acres in the Permian Basin for proceeds of approximately $153 million.
Portions of the Eagle Ford gathering line system have been temporarily isolated while the cause of potential corrosion issues is being
analyzed. We are continuing to produce from this field and have increased the use of trucking to deliver our condensate to the market which is expected to mitigate any significant impact on production. Regulatory authorities have been notified. As
we continue to verify integrity, we are bringing additional portions of the gathering system back online.
24
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial
statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our unaudited condensed consolidated financial statements requires us to make estimates and assumptions that
affect our reported results of operations and the amount of reported assets and liabilities. There have been no material changes to our critical accounting policies from those described in our Transition Report to Security Holders dated
June 30, 2013.
Redemption of Long Term Debt
On January 2, 2014, the Company issued a formal notice of redemption to noteholders of its 10.5% Senior Notes due 2014 and 7.875% Senior
Notes due 2015. All outstanding Senior Notes due 2014 and 2015 were redeemed on February 3, 2014 at the applicable call prices (see Note #3). The total aggregate principal value of the notes redeemed was $1.4 billion US Dollars, resulting in a
net expense of $25.9 million in the period.
25
Comparison of Results of Operations
Nine months Ended March 31, 2014 Compared to Nine months Ended March 31, 2013
We reported a loss from continuing operations, net of income taxes, of $98 thousand for the nine months ended March 31, 2014, compared to
a loss from continuing operations, net of income taxes, of $51.6 million for the comparable period in 2013. The following table summarizes key items of comparison and their related change for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended March 31,
|
|
|
|
|
(In thousands (except per unit and per Mcfe amounts))
|
|
2014
|
|
|
2013
|
|
|
Change
|
|
Income (loss) from continuing operations, net of income taxes
|
|
$
|
(98
|
)
|
|
$
|
(51,645
|
)
|
|
$
|
51,547
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
|
2,440,718
|
|
|
|
1,676,786
|
|
|
|
763,932
|
|
Marketing
|
|
|
326,087
|
|
|
|
59,353
|
|
|
|
266,734
|
|
Midstream
|
|
|
39,911
|
|
|
|
53,621
|
|
|
|
(13,710
|
)
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketing
|
|
|
330,764
|
|
|
|
58,566
|
|
|
|
272,198
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
247,951
|
|
|
|
79,463
|
|
|
|
168,488
|
|
Workover and other
|
|
|
23,091
|
|
|
|
10,825
|
|
|
|
12,266
|
|
Taxes other than income
|
|
|
128,853
|
|
|
|
83,399
|
|
|
|
45,454
|
|
Gathering, transportation and other
|
|
|
391,245
|
|
|
|
246,054
|
|
|
|
145,191
|
|
General and administrative
|
|
|
225,909
|
|
|
|
132,576
|
|
|
|
93,333
|
|
Depletion, depreciation and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion Full cost
|
|
|
994,534
|
|
|
|
818,695
|
|
|
|
175,839
|
|
Depreciation Midstream
|
|
|
41,600
|
|
|
|
27,110
|
|
|
|
14,490
|
|
Depreciation Other
|
|
|
20,450
|
|
|
|
26,938
|
|
|
|
(6,488
|
)
|
Rig contract termination costs
|
|
|
77,335
|
|
|
|
|
|
|
|
77,335
|
|
Accretion expense
|
|
|
6,233
|
|
|
|
1,797
|
|
|
|
4,436
|
|
Impairment of intangible asset
|
|
|
|
|
|
|
67,237
|
|
|
|
(67,237
|
)
|
Other income (expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain on derivative contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense and other
|
|
|
(318,593
|
)
|
|
|
(324,810
|
)
|
|
|
(6,217
|
)
|
Income (loss) from continuing operations before income taxes
|
|
|
158
|
|
|
|
(87,710
|
)
|
|
|
87,868
|
|
Income tax benefit (expense)
|
|
|
(256
|
)
|
|
|
36,065
|
|
|
|
(36,321
|
)
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas Mmcf
|
|
|
216,415
|
|
|
|
247,686
|
|
|
|
(31,271
|
)
|
Crude oil MBbl
|
|
|
14,871
|
|
|
|
7,722
|
|
|
|
7,149
|
|
Natural gas liquids MBbl
|
|
|
7,936
|
|
|
|
5,214
|
|
|
|
2,722
|
|
Natural gas equivalent Mmcfe
(1)
|
|
|
353,256
|
|
|
|
325,305
|
|
|
|
27,951
|
|
Average daily production Mmcfe
(1)
|
|
|
1,289
|
|
|
|
1,187
|
|
|
|
102
|
|
|
|
|
|
Average price per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price Mcf
|
|
$
|
3.89
|
|
|
$
|
3.02
|
|
|
$
|
0.87
|
|
Crude oil price Bbl
|
|
|
92.52
|
|
|
|
98.10
|
|
|
|
(5.58
|
)
|
Natural gas liquids price Bbl
|
|
|
27.82
|
|
|
|
30.16
|
|
|
|
(2.34
|
)
|
Natural gas equivalent price Mcfe
(1)
|
|
|
6.90
|
|
|
|
5.11
|
|
|
|
1.79
|
|
|
|
|
|
Average cost per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
0.70
|
|
|
|
0.24
|
|
|
|
0.46
|
|
Workover and other
|
|
|
0.07
|
|
|
|
0.03
|
|
|
|
0.04
|
|
Taxes other than income
|
|
|
0.36
|
|
|
|
0.26
|
|
|
|
0.10
|
|
Gathering, transportation and other
|
|
|
1.11
|
|
|
|
0.76
|
|
|
|
0.35
|
|
General and administrative
|
|
|
0.64
|
|
|
|
0.41
|
|
|
|
0.23
|
|
Depletion (
excludes depreciation and amortization
)
|
|
|
2.82
|
|
|
|
2.52
|
|
|
|
0.30
|
|
(1)
|
Oil and natural gas liquids are converted to equivalent gas production using a 6:1 equivalent ratio. This ratio does not assume price equivalency and given price differentials, the price for a barrel of oil equivalent
for natural gas may differ significantly from the price for a barrel of oil.
|
26
For the nine months ended March 31, 2014, oil and natural gas revenues increased $763.9
million from the same period in 2013, to $2,441 million. The increase was primarily due to the increase in crude oil and natural gas liquids (NGLs) volumes of 92.6% and 52.5%, partially offset by a reduction in natural gas volumes of 12.6%. The
change in volumes added $688.8 million in revenue. Price movements positively impacted revenues, with natural gas prices increasing 28.7% or $0.87 to $3.89 per mmcf versus $3.02 in the same period in 2013. This was partially offset by crude oil
falling 5.7% or $5.58 per barrel to $92.52 versus $98.10 in the same period in 2013. NGL prices dropped 7.7% or $2.34 to $27.82 per barrel versus $30.16 in the same period in 2013. The change in prices increased revenue by $86.6 million. Other
revenue dropped $11.4 million for the nine months ended March 31, 2014 vs. March 31, 2013.
We had marketing revenues of $326.1
million and marketing expenses of $330.8 million for the nine months ended March 31, 2014, resulting in a loss before income taxes of $4.7 million. Marketing revenues and expenses are related to the purchase and sale of third party condensate.
We had gross revenues from our midstream business of $143.8 million for the nine months ended March 31, 2014, compared to the same
period in 2013 of $105.1 million, an increase of $38.7 million. The increase in gross revenues from our midstream business primarily relates to income for gathering services relating to new production and an increase in condensate handling fees due
to additional volumes at Eagle Ford. In accordance with the financing method for a failed sale of in substance real estate we record BHP Eagle Ford Gathering revenues, net of eliminations for intercompany amounts associated with gathering and
treating services provided to us on the consolidated statements of operations. For the nine months ended March, 2014, approximately $39.9 million in revenues, after intercompany eliminations, from BHP Eagle Ford Gathering were reported in midstream
revenues on the consolidated statements of operations.
Lease operating expenses increased $168.5 million for the nine months ended
March 31, 2014, as compared to the same period in 2013. The increase was primarily due to an increase in the number of wells put online, increased water handling costs combined with increased production. We continue to move towards higher
liquids production versus gas production. The liquid volumes are more expensive to produce than gas volumes. On a per unit basis, lease operating expenses increased $0.46 per Mcfe to $0.70 per Mcfe in 2014 from $0.28 per Mcfe in 2013.
Taxes other than income increased $45.5 million for the nine months ended March 31, 2014, as compared to the same period in 2013. The
largest components of taxes other than income are production and severance taxes which are generally assessed as either a fixed rate based on production or as a percentage of gross oil and natural gas sales. Our increase in production and resulting
impact on indirect taxes in the current year was partially offset by severance tax refunds related to drilling incentives for horizontal wells in the Haynesville and Eagle Ford Shales. For the nine months ended March 31, 2014, we recorded
severance tax refunds totaling $19.7 million compared to $7.4 million in the prior year. On a per unit basis, excluding the severance tax refunds, taxes other than income were $0.42 per Mcfe in 2014 compared to $0.28 per Mcfe in 2013.
Gathering, transportation and other expense increased $145.2 million for the nine months ended March 31, 2014 as compared to the same
period in 2013. On a per unit basis, gathering transportation and other increased $0.35 per Mcfe from $0.76 per Mcfe in 2013 to $1.11 per Mcfe in 2014. The overall increase is due to higher cost per unit for liquids and an increase in liquids
volumes, combined with deficiency payments associated with unutilized gathering and treating and firm transportation capacity.
During the
nine month period, the Company continued to make modifications to the number of rigs within our rig fleet. As such, for the nine months ended March 31, 2014, we incurred costs of approximately $77.3 million associated with the early termination
of select rig contracts. This expense was recorded to
Rig contract termination costs
in the consolidated statements of operations.
General and Administrative expense increased $93.3 million for the nine months ended March 31, 2014 as compared to the same period in
2013. On a per unit basis this represents an increase of $0.23 per Mcfe, from $0.41 per Mcfe to $0.64 per Mcfe. This was caused by an increase to headcount and support activity for our operations since the previous year.
Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs
associated with evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. Depletion expense increased $175.8 million for the nine
months ended March 31, 2014, from the same period in 2013, to $994.5 million primarily due to a higher depreciable base and increased production. On a per unit basis, depletion expense increased $0.30 per Mcfe to $2.82 per Mcfe. The increase on
a per unit basis is due to capital spending and reserve additions during the nine months ended March 31, 2014.
27
Depreciation expense associated with our gas gathering systems increased $14.5 million to $41.6
million for the nine months ended March 31, 2014, as compared to the same period in 2013. The increase was due to the growth in our midstream operations from capital spending. We depreciate our gas gathering systems over a 30 year useful life
commencing on the estimated placed in service date. Depreciation expense associated with our other operating property and equipment decreased $6.5 million to $20.5 million for the nine months ended March 31, 2014, as compared to the same period
in 2013.
Interest expense and other decreased $6.2 million for the nine months ended March 31, 2014 compared to the same period in
2013. There was an increase in interest expense recorded as a result of redemption and settlement in full on February 3, 2014 of the 10.5% and 7.875% Senior Notes, including associated write off of remaining Debt Issuance Costs. This was offset
by a reduction in interest expense recorded as a result of our accounting for KinderHawk and the BHP Eagle Ford Gathering joint venture under the financing method for a failed sale of in substance real estate. For the nine months ended
March 31, 2014, we recorded approximately $116.2 million of interest expense on the financing obligations compared to $121.8 million in the prior year.
We had an income tax provision of $256 thousand for the nine months ended March 31, 2014, due to our income from operations before income
taxes of $158 thousand (combined with non-deductibles) compared to an income tax benefit of $36.1 million due to our loss from operations before income taxes of $87.7 million in the prior year. The effective tax rate for the nine months ended
March 31, 2014, was 162% compared to 41% for the nine months ended March 31, 2013.
Investment in BHP Eagle Ford Gathering
(formerly
Investment in EagleHawk)
BHP Eagle Ford Gathering had gross revenues of $83.4 million related to its Eagle Ford Shale
gathering and treating systems in the Hawkville and Black Hawk Fields for the nine months ended March 31, 2014, compared to $74.9 million for the nine months ended March 31, 2013. Gross revenues include $43.5 million and $35.7 million of
intercompany revenues that were eliminated in consolidation for the nine months ended March 31, 2014 and 2013, respectively. Total operating expenses for BHP Eagle Ford Gathering for the nine months ended March 31, 2014, of $67.3 million
included $36.5 million in gathering, transportation and other expenses and $24.4 million in depreciation expense. Total operating expenses for the nine months ended March 31, 2013 of $48.1 million included $27.4 million in gathering,
transportation and other expenses and $15.8 million in depreciation expense. Gathering, transportation and other expenses for BHP Eagle Ford Gathering consist of costs to operate the pipelines, such as treating, processing, measuring and
transporting expenses. Depreciation expense on BHP Eagle Ford Gatherings gathering and treating systems is calculated based on a 30 year useful life commencing on the estimated placed in service date. A review of deferred tax balances has
resulted in a restatement of the deferred tax asset balance for June 30, 2013 and an associated change to accumulated deficit.
28