Sabine Oil & Gas Corporation Announces Fourth Quarter and Full Year 2014 Financial and Operating Results

HOUSTON, March 31, 2015 /PRNewswire/ -- Sabine Oil & Gas Corporation ("Sabine" or the "Company") (OTCQB:SOGC) today reported its fourth quarter and full year 2014 financial and operating results.

(Logo: http://photos.prnewswire.com/prnh/20130325/MM83201LOGO)

Key 2014 Results and Events:

• Closed the business combination of Sabine Oil & Gas LLC and Forest Oil Corporation on December 16, 2014.  The results presented in this press release include 15 days of operating data for the combined entity and results for Sabine Oil & Gas LLC on a stand-alone basis prior to the combination.
• Increased average daily production by 18% to 205 MMcfe/d in 2014, from 175 MMcfe/d in 2013. Excluding the effects of the North Texas property divestiture in late 2013, the average daily production in 2014 increased by 32% compared to the same period in 2013 on a pro forma basis.  Oil production increased by 55% to 5,944 Bbl/d over the same period in 2013.
• Oil and natural gas liquids (collectively, "liquids") production volumes comprised 53% of revenues and 34% of total production for 2014.
• Adjusted EBITDA for 2014 was $330.9 million, representing a 12% increase over 2013.
• In East Texas, completed nine Cotton Valley horizontal wells which had an average rate for a 30-day period ("IP30") of over 8.8 MMcfe/d, with 17% liquids.
• Also in East Texas, completed eight of the remaining 15 Haynesville Shale wells covered under a joint development agreement which collectively averaged an IP30 of over 8.0 MMcf/d.
• In the Eagle Ford Shale, completed 34 wells in the Shiner Area in northern DeWitt County and southern Lavaca County which collectively averaged an IP30 of over 900 BOEPD, with 42% oil and 73% liquids.
• Also, in the Eagle Ford Shale, completed eight wells in the Sugarkane Area in southern DeWitt County which collectively averaged an IP30 of over 1,795 BOEPD, with 21% oil and 58% liquids.
• In North Texas, completed 17 Granite Wash wells which collectively averaged an IP30 of over 950 BOEPD, with 57% oil and 80% liquids.

"We recognize that market dynamics have changed considerably in the past year, which has impacted the Company's financial position.  Our management team and board of directors are taking proactive steps to strengthen our balance sheet and enhance liquidity. We achieved a 31% increase in revenues from production of oil, natural gas liquids and natural gas, and a 12% increase in Adjusted EBITDA for the year.  We remain focused on continuing to manage our asset portfolio and executing our business strategy," said David Sambrooks, Chairman, President and Chief Executive Officer.  "To that end, we have retained Lazard and Kirkland & Ellis LLP to advise management and the board of directors on strategic alternatives related to our capital structure.  We intend to explore alternatives aimed at enhancing our liquidity and strengthening our balance sheet.  We fully expect to continue operating in the ordinary course throughout this process."

Sabine and Forest Oil Business Combination Transaction

On December 16, 2014, Sabine Oil & Gas LLC and Forest Oil Corporation closed the all-stock business combination. Immediately following the combination, the legacy Sabine Oil & Gas LLC investors owned approximately 73.5% of the economic interest in the combined company and approximately 40% of the voting power of the combined company. Sabine Oil & Gas LLC was treated as the accounting acquirer in the combination, and accordingly, our historical financial and operating results for periods prior to the combination are the financial and operating results of Sabine Oil & Gas LLC.

Results of the Fourth Quarter 2014

Production volumes during the fourth quarter of 2014 were 20.2 Bcfe, an increase of 0.8 Bcfe or 4% compared to production of 19.4 Bcfe during the fourth quarter of 2013. The increase in production is primarily due to the Forest Oil business combination and the Company's development program.

Revenues from production of oil, natural gas liquids and natural gas decreased from $109.3 million in the fourth quarter of 2013 to $107.0 million for the fourth quarter of 2014, a decrease of 2%. This decrease of $2.4 million was a result of a decrease in average prices per Mcfe of 6% (before the effects of economic hedges), partially offset by an increase in production of 4%.

The Company's realized average price for natural gas including hedges was $4.28 per Mcf in the fourth quarter of 2014, or $0.17 per Mcf higher than the Company's unhedged realized average price of $4.11 per Mcf. The Company's realized average price of oil including hedges was $69.10 per Bbl in the fourth quarter of 2014, or $6.56 per Bbl higher than the Company's unhedged realized average price of $62.54 per Bbl.  For fourth quarter of 2014, our hedged volumes were approximately 83% of natural gas volumes and 96% of oil volumes, which resulted in a realized gain on such derivative instruments of $6.6 million. For fourth quarter of 2013, our hedged volumes were approximately 69% and 79% of our natural gas and oil volumes, respectively, which resulted in a realized gain on such derivative instruments of $12.2 million.

Lease operating expenses increased from $12.9 million for the fourth quarter of 2013 to $14.2 million in the fourth quarter of 2014, an increase of 10%. The increase in lease operating expense of $1.3 million is primarily due to an increase in producing properties as a result of development activities in South Texas, partially offset by the December 2013 sale of our interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area. Lease operating expenses increased on a per unit basis from $0.67 per Mcfe in the fourth quarter of 2013 to $0.71 per Mcfe in the fourth quarter of 2014.

Marketing, gathering, transportation and other expenses increased from $5.1 million in the fourth quarter of 2013 to $6.5 million in the fourth quarter of 2014. Marketing, gathering, transportation and other expense increased on a per unit basis from $0.26 per Mcfe in the fourth quarter of 2013 to $0.32 per Mcfe in the fourth quarter of 2014. The per unit increase of $0.06 per Mcfe is primarily associated with increasing gas volumes associated with our South Texas development activities as well as gas volumes associated with our Haynesville development activities in East Texas, which were subject to higher fees due to lack of pipeline infrastructure, partially offset by increasing oil volumes associated with our development activities in North Texas and South Texas regions which are not subject to gathering and transportation charges.

Production and ad valorem taxes decreased from $5.3 million in the fourth quarter of 2013 to $2.6 million in the fourth quarter of 2014, a decrease of 51%. Production and ad valorem taxes decreased on a per unit basis from $0.27 per Mcfe in the fourth quarter of 2013 to $0.13 per Mcfe in the fourth quarter of 2014. The decrease is primarily due to production tax refunds for high cost gas wells during the fourth quarter of 2014. The Company expects to experience continued variability in its production taxes as a result of well types and amount, and timing of approval of high cost gas tax exemptions. Production and ad valorem taxes as a percentage of oil, natural gas and natural gas liquids revenues were 2% and 5% for the fourth quarter of 2014 and 2013, respectively.

General and administrative expenses increased from $8.7 million in the fourth quarter of 2013 to $9.8 million in the fourth quarter of 2014, an increase of $1.1 million, or 13%, primarily as a result of higher overhead associated with our growing business. General and administrative expenses increased on a per unit basis from $0.45 per Mcfe in fourth quarter of 2013 to $0.48 per Mcfe in fourth quarter of 2014.

DD&A increased from $42.9 million in the fourth quarter of 2013 to $46.5 million in the fourth quarter of 2014, an increase of $3.6 million and 8%. Depletion, depreciation, and amortization increased on a per unit basis from $2.21 per Mcfe in the fourth quarter of 2013 to $2.30 per Mcfe in the fourth quarter of 2014. The increase in the DD&A expense is primarily the result of reductions to proved reserves due to the sale of certain oil and natural gas properties in North Texas during the fourth quarter of 2013 as well as an increase in the amortization base as a result of development activities without a proportionate increase in reserve volumes.

In the fourth quarter of 2014, there were non-cash impairment charges related to oil and natural gas properties of $247.7 million and impairment charges for other assets of $0.2 million. Additionally, due to a drop in commodity prices and the $247.7 million ceiling impairment, a December 31, 2014 impairment test resulted in the impairment of $173.5 million of goodwill for the year ended December 31, 2014. In 2013, there were impairment charges related to other assets of $1.1 million. There were no impairments related to oil and natural gas properties recognized in 2013 as a result of favorable average unweighted first day of the month pricing for the year ended December 31, 2013 of $3.67 per MMbtu versus $2.76 per MMbtu as of December 31, 2012 as well as favorable performance from our 2013 development activities.

Other operating expenses in the fourth quarter of 2014 relate primarily to $17.5 million of transaction costs related to the Forest Oil business combination as compared to $0.8 million of other operating income for the fourth quarter of 2013.

Interest expense increased from $25.8 million in the fourth quarter of 2013 to $35.2 million in the fourth quarter of 2014, an increase of $9.4 million, or 36%, primarily as a result of increased borrowings under the Company's revolving credit facility and $5.8 million of interest expenses on the 2019 Notes and the 2020 Notes. Additionally we capitalized $1.5 million and $2.9 million of interest expense for the quarters ended December 31, 2014 and 2013, respectively.

The Company recognized a gain on derivative contracts of $123.3 million and loss on derivative contracts of $7.0 million for the year ended December 31, 2014 and 2013, respectively. The amount of future gain or loss recognized on derivative instruments is dependent upon future commodity prices.

Results of the Year ended December 31, 2014

Production volumes during the year ended December 31, 2014 were 75.0 Bcfe, an increase of 11.2 Bcfe or 18% compared to production of 63.8 Bcfe during the year ended December 31, 2013. The increase in production is primarily due to the Forest Oil business combination and the Company's development program.

Revenues from production of oil, natural gas liquids and natural gas increased from $354.2 million in 2013 to $462.4 million in 2014, an increase of 31%. This increase of $108.1 million was a result of an increase in average prices per Mcfe of 11% (before the effects of economic hedges), coupled with an increase in production of 18%.

The Company's realized average price for natural gas including hedges was $4.30 per Mcf in 2014 or $0.14 per Mcf lower than the Company's unhedged realized average price of $4.44 per Mcf. The Company's realized average price of oil including hedges was $81.79 per Bbl in 2014 or $1.78 per Bbl lower than the Company's unhedged realized average price of $83.57 per Bbl.  In 2014, our hedged volumes were approximately 82% of natural gas volumes and 81% of oil volumes, which resulted in a realized loss on such derivative instruments of $10.8 million. In 2013, our hedged volumes were approximately 80% and 71% of our natural gas and oil volumes, respectively, which resulted in a realized gain on such derivative instruments of $46.2 million.

Lease operating expenses increased from $44.6 million in 2013 to $51.3 million in 2014, an increase of 15%. The increase in lease operating expense of $6.6 million is primarily due to an increase in producing properties as a result of development activities in South Texas partially offset by the December 2013 sale of our interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area. Lease operating expenses decreased on a per unit basis from $0.70 per Mcfe in 2013 to $0.68 per Mcfe in 2014. The decrease of $0.02 per Mcfe is primarily due to higher production volumes associated with increased completion activity in the last 12 months and the sale of interests in higher cost areas.

Marketing, gathering, transportation and other expenses increased from $17.6 million in 2013 to $23.6 million in 2014. Marketing, gathering, transportation and other expense increased on a per unit basis from $0.28 per Mcfe in 2013 to $0.32 per Mcfe in 2014. The per unit increase of $0.04 per Mcfe is primarily associated with increasing gas volumes associated with our South Texas development activities as well as gas volumes associated with our Haynesville development activities in East Texas, which were subject to higher fees due to lack of pipeline infrastructure, partially offset by increasing oil volumes associated with our development activities in North Texas and South Texas regions which are not subject to gathering and transportation charges.

Production and ad valorem taxes increased from $17.8 million in 2013 to $18.2 million in 2014, an increase of 2%. Production and ad valorem taxes decreased on a per unit basis from $0.28 per Mcfe in 2013 to $0.24 per Mcfe in 2014. The decrease is primarily due to a decrease in North Texas production due to the December 2013 sale of our interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area. This decrease is partially offset by increases primarily due to increased production in the South Texas region which is incurring higher production taxes on oil, natural gas liquids and natural gas production. The Company expects to experience continued variability in its production taxes as a result of well types and amount, and timing of approval of high cost gas tax exemptions. Production and ad valorem taxes as a percentage of oil, natural gas and natural gas liquids revenues were 4% and 5% for 2014 and 2013, respectively.

General and administrative expenses increased from $27.5 million in 2013 to $30.4 million in 2014, an increase of $2.9 million, or 11%, primarily as a result of higher overhead associated with our growing business. General and administrative expenses decreased on a per unit basis from $0.43 per Mcfe in 2013 to $0.41 per Mcfe in 2014 due to increased production without a proportionate increase in general and administrative expenses.

DD&A increased from $137.1 million in 2013 to $189.5 million in 2014, an increase of $52.4 million. Depletion, depreciation, and amortization increased on a per unit basis from $2.15 per Mcfe in 2013 to $2.53 per Mcfe in 2014, or an increase of 18%. The increase in the DD&A expense is primarily the result of reductions to proved reserves due to the sale of certain oil and natural gas properties in North Texas during the fourth quarter of 2013 as well as an increase in the amortization base as a result of development activities without a proportionate increase in reserve volumes.

In 2014, there were non-cash impairment charges related to oil and natural gas properties of $247.7 million, impairment charges for gas gathering and processing equipment of $1.7 million and impairment charges for other assets of $0.2 million. Additionally, due to a drop in commodity prices and the $247.7 million ceiling impairment, a December 31, 2014 impairment test resulted in the impairment of $173.5 million of goodwill for the year ended December 31, 2014. In 2013, there were impairment charges related to other assets of $1.1 million. There were no impairments related to oil and natural gas properties recognized in 2013 as a result of favorable average unweighted first day of the month pricing for the year ended December 31, 2013 of $3.67 per MMbtu versus $2.76 per MMbtu as of December 31, 2012 as well as favorable performance from our 2013 development activities.

Other operating expenses for the year ended December 31, 2014 relate primarily to $25.5 million of transaction costs related to the Forest Oil business combination and $2.0 million for the write-off of previously deferred public offering costs related to offerings which were aborted prior to our decision to commence the Forest Oil business combination, partially offset by the gain on sale of other assets of $1.5 million, as compared to $0.9 million of other operating income for the year ended December 31, 2013.

Interest expense increased from $99.5 million in 2013 to $115.6 million in 2014, an increase of $16.1 million, or 16%, primarily as a result of increased borrowings under the Company's revolving credit facility and $5.8 million of interest expenses on the 2019 Notes and the 2020 Notes. Additionally we capitalized $6.5 million and $13.0 million of interest expense for the years ended December 31, 2014 and 2013, respectively.

The Company recognized a gain on derivative contracts of $121.7 million and $0.8 million for the year ended December 31, 2014 and 2013, respectively. The amount of future gain or loss recognized on derivative instruments is dependent upon future commodity prices.

Debt/Liquidity

As of December 31, 2014, the Company's borrowing base under its revolving first lien credit facility was $1 billion, with borrowings of approximately $545 million and approximately $29 million in letters of credit, providing $426 million of availability.

As of March 15, 2015, the Company had fully drawn its revolving credit facility and had approximately $327 million in cash on hand with an outstanding balance of $1 billion under the revolving credit facility, including approximately $29 million of letters of credit. The Company's borrowing base is currently being re-determined in accordance with the terms governing the revolving credit facility.  Based on discussions with the lenders under the revolving credit facility, the Company believes that its borrowing base may be reduced significantly.

In addition, the report of the Company's independent registered public accounting firm contained in its Annual Report on Form 10-K filed today with the Securities and Exchange Commission ("SEC") includes an explanatory paragraph regarding the substantial doubt about its ability to continue as a going concern due to the uncertainty associated with its ability to repay its outstanding debt obligations as they become due. For a discussion of the impact of this explanatory paragraph, current market conditions, our combination with Forest Oil and other factors on our liquidity and our ability to comply with the covenants in our debt agreements, please read our Annual Report on Form 10-K filed today with the SEC.

Hedging

As of March 31, 2015, the Company has NYMEX hedges in place for the remaining calendar year of 2015 on approximately 218,000 MMbtu/d of its projected natural gas production, at a weighted average price of $4.15/ MMBtu, and 6,967 Bbl/day of oil production at a weighted average price of $89.85/bbl.  For the calendar year of 2016, the Company has hedge contracts in place for 67,000 MMbtu/d of its projected natural gas production at a weighted average price of $3.26/MMbtu, and 2,750 Bbl/day of oil production at a weighted average price of $62.31/Bbl.  For the calendar year of 2017, the Company has hedge contracts in place for 1,500 Bbl/day of oil production at a weighted average price of $64.80/Bbl.

Year-End Reserves 

Year-end 2014 proved reserves, as determined by the Company's independent reserve engineers and calculated pursuant to SEC guidelines, increased by 62% from approximately 839 Bcfe to 1,357 Bcfe. The changes in proved reserves from 2013 include the purchase of approximately 382 Bcfe of reserves associated primarily with the Forest Oil Corporation business combination and two other acquisitions.  Additionally, the downward revision of approximately 98 Bcfe was primarily a result of the reclassification of certain proved undeveloped oil reserves in the Eagle Ford to probable undeveloped reserves as a result of the Company reducing its development program and rig count due to a decline in oil and natural gas prices in late 2014. In addition to pricing, 2014 downward revisions were also attributable to a combination of adjustments in working interest and performance revisions.  In 2014, the Company also had 308.1 Bcfe of extensions and discoveries, which were primarily due to refocusing the Company's development program on primarily gas assets in East Texas.

Proved reserves consisted of 989.8 Bcf of natural gas, 20.1 Mbbls of oil and 41.1 Mbbls of natural gas liquids. The pre-tax present value ("PV-10") of the Company's proved reserves discounted at 10% and using the year-end SEC pricing was $1,711 million, which is an increase of $360 million compared to the PV-10 at year-end 2013 of $1,351 million.

The following table reflects the changes in the proved reserves estimates from year-end 2013 to 2014:

About Sabine Oil & Gas Corporation

Sabine Oil & Gas Corporation is an independent energy company engaged in the acquisition, production, exploration and development of onshore oil and natural gas properties in the United States. Sabine's current operations are principally located in the Cotton Valley Sand and Haynesville Shale in East Texas, the Eagle Ford Shale in South Texas, the Granite Wash in the Texas Panhandle and the North Louisiana Haynesville.  For more information about Sabine, please visit www.sabineoil.com

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This press release may include "forward-looking statements" within the meaning of the U.S. Private Litigation Securities Reform Act of 1995.  All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements include, but are not limited to forward-looking statements about acquisitions, divestitures and trades, potential strategic alliances, timing and payment of dividends, the availability of capital, and the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company's drilling program, production, hedging activities, capital expenditure levels and other guidance that may be included in this press release. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to the Company's financial performance and results, availability of sufficient cash flow to execute its business plan, prices and demand for oil, natural gas and natural gas liquids, the ability to replace reserves and efficiently develop current reserves, the ability to access the capital markets and finance operations, including capital expenditures, risk relating to our combination with Forest Oil Corporation, including our ability to integrate the operations of the two companies and litigation related to the combination, and other important factors that could cause actual results to differ materially from those projected as described in the Company's reports filed with the Securities and Exchange Commission. See "Risk Factors" in the Company's Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

(1) Use of Non-GAAP Financial Measures

"Adjusted EBITDA" is a non-GAAP financial measure which Sabine uses in its business. This measure is not calculated or presented in accordance with US GAAP.

We believe the presentation of Adjusted EBITDA provides useful information to investors to evaluate the operations of our business excluding certain items and for the reasons set forth below. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow operating activities or any other measure of financial performance presented in accordance with US GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

We use Adjusted EBITDA for the following purposes:

• to assess the financial performance of our assets, without regard to financing methods, capital structure or historical cost basis;
• to assess our operating performance and return on capital as compared to those of other companies in the oil and gas industry, without regard to financing or capital structure;
• to assess the viability of acquisition and capital expenditure projects and the overall rates of return on alternative investment opportunities;
• to assess the ability of our assets to generate cash sufficient to pay interest costs and support indebtedness;
• for various purposes, including strategic planning and forecasting;
• the $700 million term loan facility and the indenture governing the 9.75% Senior Notes due 2017 contain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness unless the ratio of adjusted consolidated EBITDA to adjusted consolidated interest expense and other fixed charges over the trailing four fiscal quarters will be at least 2.0 to 1.0 (subject to exceptions for borrowings within certain limits);
• the 7.25% Senior Notes Due 2019 and the 7.50% Senior Notes due 2020 contain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness unless the ratio of adjusted consolidated EBITDA to adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.25 to 1.00 (subject to exceptions within certain limits); and
• the Second Amended and Restated Credit Agreement, dated as of December 16, 2014, a $2 billion reserve based revolving credit facility with an initial borrowing base of $1 billion requires us to comply with a financial maintenance ratio in the form of a first lien secured leverage ratio not to exceed 3.0 to 1.0 which is defined as a ratio of consolidated first lien secured debt to Adjusted EBITDA for the period of four fiscal quarters then ending.

SOURCE Sabine Oil & Gas Corporation

Related Links

http://www.sabineoil.com