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8-K - FORM 8-K - Energy XXI Ltd	v403523_8-k.htm
EX-99.1 - EXHIBIT 99.1 - Energy XXI Ltd	v403523_ex99-1.htm

Exhibit 99.2

Financing Transactions

In connection with the completion of this offering, we expect to amend our revolving credit facility, to, among other things, reduce the total borrowing base availability to $500 million, allow for the distribution of certain assets related to the Grand Isle gathering system (the “Grand Isle Assets”), provide for the provision of a security interest by Energy XXI USA, Inc. (“Intermediate Holdco”) in the Grand Isle Assets in connection with a distribution of those assets in view of a proposed sale (as discussed below), provide for certain non-core asset sales (as discussed below) to be conducted without immediate reduction in our borrowing base subject to certain conditions and permit the issuance of the notes offered hereby. Of the $500 million of availability under our amended revolving credit facility, $150 million is expected to be allocated exclusively for a separate tranche of borrowings by EPL and its subsidiaries. In addition, the amendment is expected to make certain modifications to the existing financial covenants. The covenants will apply to, and be tested at, EGC and EPL separately for so long as EPL’s 8.25% Senior Notes due 2018 (the “EPL 8.25% Notes”), which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”), remain outstanding. As a result of the amendment to our revolving credit facility, we expect to remain in compliance with the financial covenants thereunder for the foreseeable future. The amendment is conditioned upon our receiving gross proceeds in this offering of at least $1.0 billion. For more information about the terms of the amended revolving credit facility, please see “Description of Other Indebtedness — Revolving Credit Facility.”

In connection with the amendment of our revolving credit facility, EGC is expected to enter into an intercompany loan with EPL, whereby EGC will loan to EPL a portion of the proceeds of this offering sufficient to repay a portion of the currently outstanding borrowings under the EPL tranche of our revolving credit facility. We expect that the intercompany loan will be secured by a second priority lien on certain assets of EPL that secure EPL’s obligations under the amended revolving credit facility. EGC may release the collateral securing the intercompany loan at any time.

In addition, EXXI has stated that it intends to contribute $50 million in cash to us within 10 days following the closing of this offering. As of February 20, 2015, EXXI had approximately $102 million of cash on hand.

Potential Divestitures

We are pursuing potential arrangements with third parties to monetize certain midstream assets or sell certain non-core oil and gas properties to enable us to further reduce the amount of our required capital commitments. The Grand Isle gathering system was deregulated on February 1, 2015, and we continue to evaluate and pursue the monetization of the Grand Isle Assets. These assets will be distributed from EGC to Intermediate Holdco prior to the completion of this offering, and Intermediate Holdco will guarantee the notes on a non-recourse basis limited to the value of the equity interests in us that it pledges to secure its guarantee as well as the Grand Isle Assets that it will grant a security interest in to secure its guarantee.

Additionally, with respect to our potential non-core asset divestiture of operated and non-operated interests in certain of our GoM Shelf properties being marketed by The Oil & Gas Asset Clearinghouse, bids have been submitted and we have begun negotiating a potential disposition agreement. The package includes approximately 6,900 BOE/d of production from approximately 28 fields.

There can be no assurance any of these discussions or transactions will prove successful. We cannot provide any assurance that we will be able to sell these assets on satisfactory terms, if at all.

SUMMARY RESERVE AND PRO FORMA OPERATING DATA

The following estimates of the total EXXI net proved oil and natural gas reserves of our oil and gas properties located entirely within the U.S. as of June 30, 2014 and 2013 are based on evaluations prepared by our internal reservoir engineers and were audited by Netherland Sewell & Associates, Inc., independent petroleum engineering consultants (“NSAI”). The estimates of total EXXI net proved oil and gas reserves as of June 30, 2012 were prepared by NSAI. The estimates of ECG (excluding EPL) net proved oil and gas reserves as of June 30, 2014 are based on our internally-generated reserve estimates that have not been audited or prepared by NSAI. The estimates of EPL net proved reserves as of June 30, 2014 were prepared by NSAI.

The estimates of net proved oil and natural gas reserves of EXXI, EGC (excluding EPL) and EPL as of December 31, 2014 were prepared by our internal reservoir engineers and have not been audited by NSAI. Our estimated proved reserves as of December 31, 2014 have been calculated using NYMEX forward strip pricing as of February 9, 2015 and estimated costs as of February 9, 2015 based, in part, on recent January 2015 field estimates. These estimates reflect an approximate 20% reduction in lease operating expenses as compared to the lease operating expenses used in calculating our estimated proved reserves as of June 30, 2014, due primarily to synergies from the EPL Acquisition, improvements in operating practices and pricing and cost reductions in response to recent declines in crude oil and natural gas prices. These reserve estimates also reflect actual production for the six months ended December 31, 2014 and reductions in planned capital expenditures as compared to the June 30, 2014 reserve report of EXXI. No significant additions of new reserves subsequent to June 30, 2014 are included in our internal estimates, and we only revised our prior estimates in our internal reserves when supported by additional production data, newly acquired data or continued field studies.

Except as noted above, reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost changes except by contractual arrangements. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available. Please read “Risk Factors — Risks Related to Our Business — Our actual recovery of reserves may differ from our proved reserve estimates” and “— Certain proved reserve estimates in this offering memorandum have not been audited or prepared by our independent petroleum engineering consultants.”

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and millions of British thermal units (“MMBtu”) for each of the periods indicated were as follows:


	December 31, 2014			June 30, 2014
EGC (excluding EPL):
Total Proved Reserves (MMBOE)		140.7			156.7
Proved developed producing (MMBOE)		66.2			74.5
Proved developed non-producing (MMBOE)		13.9			13.3
Proved undeveloped (MMBOE)		60.6			68.9
Liquids as a percentage of Proved Reserves⁽¹⁾		78	%		79	%
Proved Developed Reserves as a Percent of Proved Reserves		57	%		56	%
PV-10 Value (in millions)⁽²⁾⁽³⁾	$	2,775		$	5,119
Standardized measure of discounted future net cash flows (in millions)⁽⁴⁾		(4	)	$	3,983
EPL:
Total Proved Reserves (MMBOE)		71.1			89.5
Proved developed producing (MMBOE)		29.5			38.5
Proved developed non-producing (MMBOE)		18.4			23.6
Proved undeveloped (MMBOE)		23.2			27.4
Liquids as a percentage of Proved Reserves⁽¹⁾		67	%		68	%
Proved Developed Reserves as a Percent of Proved Reserves		67	%		69	%
PV-10 Value (in millions)⁽²⁾⁽³⁾	$	1,044		$	2,483
Standardized measure of discounted future net cash flows (in millions)⁽⁴⁾		(4	)	$	1,965


	December 31, 2014			June 30,
	December 31, 2014			2014			2013			2012
EXXI:
Total Proved Reserves (MMBOE)		211.8			246.2			178.5			119.6
Proved developed producing (MMBOE)		95.7			113.0			91.0			62.5
Proved developed non-producing (MMBOE)		32.3			36.9			18.5			19.2
Proved undeveloped (MMBOE)		83.8			96.3			69.0			37.9
Liquids as a percentage of Proved Reserves⁽¹⁾		75	%		75	%		75	%		71	%
Proved Developed Reserves as a Percent of Proved Reserves		60	%		61	%		61	%		68	%
PV-10 Value (in millions)⁽²⁾⁽³⁾	$	3,819		$	7,602		$	6,150		$	4,297
Standardized measure of discounted future net cash flows (in millions)⁽⁴⁾		(5	)	$	5,948		$	4,482		$	3,305
Prices Used in Calculating Reserves
(Natural Gas per MMbtu)		(6	)	$	4.10		$	3.63		$	3.30
(Crude Oil per Bbl)		(6	)	$	103.80		$	108.24		$	113.36

(1)

Liquids include crude oil, condensate and natural gas liquids.

(2)

PV-10 reflects the present value of our estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization expense, and discounted at 10% per year before income taxes.

(3)

The closest GAAP measure to PV-10, a non-GAAP measure, is the standardized measure of discounted future net cash flows. We believe PV-10 is a helpful measure in evaluating the value of our oil and gas reserves and many securities analysts and investors use PV-10. We use PV-10 in our ceiling test computations, and we also compare PV-10 against our debt balances. The following table is a reconciliation between PV-10 and the standardized measure of discounted future net cash flows:


	June 30,
	2014		2013		2012
	(in thousands)
PV-10 Value	$	7,601,504	$	6,149,636	$	4,297,445
Future income taxes (discounted at 10%)		1,653,979		1,668,114		991,956
Standardized measure of discounted future net cash flows relating to oil and natural gas reserves⁽⁴⁾	$	5,947,525	$	4,481,522	$	3,305,489

(4)

The standardized measure of discounted future net cash flows, which reflects the after-tax present value of discounted future net cash flows, relating to proved oil and natural gas reserves was prepared in accordance with the definitions and guidelines of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas. Future cash flows as of June 30, 2014 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended June 30) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at fiscal year-end, based on fiscal year-end costs and assuming the continuation of existing economic conditions. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of our oil and natural gas properties.

(5)

GAAP does not prescribe any corresponding measure for PV-10 as of a date other than year-end or for reserves calculated using other than SEC prices. Accordingly, it is not practicable for us to reconcile these additional PV-10 measures as of December 31, 2014 to GAAP standardized measure of discounted future net cash flows.

(6)

The following table sets forth the NYMEX strip prices as of February 9, 2015 used in calculating the reserves as of December 31, 2014.


Year	Crude Oil (per Bbl)		Natural Gas (per MMbtu)
2015	$	56.25	$	2.76
2016		62.48		3.21
2017		65.00		3.50
2018		67.31		3.63
2019		69.10		3.72
2020		70.45		3.79
2021		71.30		3.91
2022		71.59		4.02
2023 and thereafter		71.64		4.13

The following table sets forth summary historical information with respect to EGC’s and EPL’s combined oil and natural gas production for the year ended June 30, 2014 and the six months ended December 31, 2014.

The EGC production data for the year ended June 30, 2014 presented below was derived from our Parent’s 2014 Annual Report, which is incorporated by reference in this offering memorandum.

The EPL production data for the year ended June 30, 2014 was derived by adding EPL’s production reported in EPL’s Annual Report on Form 10-K for the year ended December 31, 2013 to its production reported in EPL’s Transition Report reported in Form 10-K for the period from January 1, 2014 through June 30, 2014, and then subtracting its production reported in EPL’s Quarterly Report on Form 10-Q for the six months ended June 30, 2013.


	Production for the Year Ended June 30, 2014								Production for the Six Months Ended December 31, 2014
	EGC Historical		EPL Adjusted		Other GOM Transactions		EGC Pro Forma Combined		Production for the Six Months Ended December 31, 2014
Sales Volumes per Day
Oil (MBbl)		30.1		15.4		0.7		46.1		41.8
Natural Gas (MMcf)		89.7		27.0		0.4		117.1		98.6
Total (MBOE)		45.1		19.9		0.7		65.6		58.2

Energy XXI Ltd - FORM 8-K - EX-99.2 - EXHIBIT 99.2 - March 4, 2015

Attached files

Exhibit 99.2

Financing Transactions

Potential Divestitures

SUMMARY RESERVE AND PRO FORMA OPERATING DATA

Energy XXI Ltd Reports