Forest Oil Announces Fourth Quarter and Year-End 2013 Results Fourth Quarter 2013 Average Net Sales Volumes of 165 MMcfe/d (62% Natural Gas, 38% Liquids) Fourth Quarter 2013 Average Net Sales Volumes of 111 MMcfe/d (68% Natural Gas, 32% Liquids) Pro Forma for Divestitures 2013 Average Oil Net Sales Volumes Increase 55% Compared to 2012 Pro Forma for Divestitures 2013 Average Liquids Net Sales Volumes Increase 41% Compared to 2012 Pro Forma for Divestitures 2013 Estimated Proved Reserves of 625 Bcfe; Oil Reserves Increase 30% Compared to 2012 Pro Forma for Divestitures 2013 Drill Bit Reserve Replacement of 197% with Drill Bit Finding and Development Costs of $2.19 per Mcfe Business Wire DENVER -- February 25, 2014 Forest Oil Corporation (NYSE:FST) (Forest or the Company) today announced financial and operational results for the fourth quarter and full-year 2013 and provided year-end estimated proved reserves. References to pro forma results exclude asset sales completed during 2012 and 2013. For the three months ended December 31, 2013, Forest reported net earnings of $106 million, or $0.89 per diluted share, compared to net earnings of $2 million, or $0.02 per share in the third quarter of 2013. Net earnings for the fourth quarter of 2013 included the following items: *Net gain on asset dispositions of $202 million ($129 million net of tax) *Unrealized losses on derivative instruments of $9 million ($6 million net of tax) *Rig stacking costs of $4 million ($2 million net of tax) *Decrease in the valuation allowance of deferred tax assets, net of non-deductible stock-based compensation costs, goodwill reduction, and other of $38 million ($38 million net of tax) *Ceiling test write-down of oil and natural gas properties of $58 million ($37 million net of tax) *Employee-related asset disposition costs of $6 million ($4 million net of tax) *Net loss on early debt extinguishment of $24 million ($15 million net of tax) Without the effect of these items, Forest’s results for the fourth quarter were as follows: *Adjusted net earnings of $3 million, or $0.02 per diluted share, compared to adjusted net earnings of $7 million or $0.06 per share, in the third quarter of 2013 *Adjusted EBITDA of $65 million compared to adjusted EBITDA of $85 million in the third quarter of 2013 *Adjusted discretionary cash flow of $37 million compared to adjusted discretionary cash flow of $54 million in the third quarter of 2013. The decreases in net earnings, EBITDA, and discretionary cash flow, each on an adjusted basis, were primarily the result of the Texas Panhandle asset divestiture in the fourth quarter of 2013. Average Net Sales Volumes, Average Realized Prices, and Revenues Forest's average net sales volumes for the three months ended December 31, 2013, were 165 MMcfe/d. Excluding volumes associated with the Texas Panhandle divestiture that closed on November 25, 2013, fourth quarter 2013 net sales volumes averaged 111 MMcfe/d. This compares to third quarter 2013 average net sales volumes of 114 MMcfe/d excluding asset sales. During the fourth quarter, the company-wide differential for crude oil was $6.69 per Bbl less than the NYMEX West Texas Intermediate (WTI) price, compared to $2.88 per Bbl less than the WTI price in the third quarter of 2013. The decrease was primarily the result of a narrowing of the Light Louisiana Sweet (LLS) premium relative to WTI that the Company received for its oil production in the Eagle Ford and Ark-La-Tex areas. The following table details the components of average net sales volumes, average realized prices, and revenues for the three months ended December 31, 2013: Three Months Ended December 31, 2013 Gas Oil NGLs Total (MMcf/d) (MBbls/d) (MBbls/d) (MMcfe/d) Average Net Sales Volumes 101.8 5.3 5.2 164.7 Average Realized Prices Gas Oil NGLs Total ($/Mcf) ($/Bbl) ($/Bbl) ($/Mcfe) Average realized prices not including realized derivative $ 3.07 $ 90.82 $ 32.15 $ 5.84 gains (losses) Realized gains (losses) on 0.52 (0.65 ) - 0.30 NYMEX derivatives Average realized prices including realized derivative $ 3.59 $ 90.16 $ 32.15 $ 6.14 gains (losses) Revenues (in thousands) Gas Oil NGLs Total Revenues not including realized derivative gains $ 28,745 $ 44,500 $ 15,240 $ 88,485 (losses) Realized gains (losses) on 4,884 (320 ) - 4,564 NYMEX derivatives Revenues including realized $ 33,629 $ 44,180 $ 15,240 $ 93,049 derivative gains (losses) The following table details the components of average net sales volumes for the fourth quarter of 2013 and full-year 2013 excluding asset divestitures: Gas Oil NGLs Total (MMcf/d) (MBbls/d) (MBbls/d) (MMcfe/d) Average Net Sales Volumes Fourth Quarter 2013 75.0 3.7 2.3 111.1 Full Year 2013 79.2 3.4 2.1 112.3 Total Cash Costs Forest's total cash costs for the fourth quarter of 2013, excluding stock-based compensation and employee-related asset disposition costs, decreased 17% to $53 million, compared to $64 million in the third quarter of 2013. Total cash costs per-unit for the fourth quarter of 2013 increased 5% to $3.48 per Mcfe, compared to $3.31 per Mcfe in the third quarter of 2013, primarily as a result of lower equivalent production volumes and having a greater proportion of higher operating cost oil properties following the sale of the Texas Panhandle assets. The following table details the components of total cash costs for the comparative periods: Three Months Ended December 31, Per Mcfe September 30, Per Mcfe 2013 2013 (In thousands, except per-unit amounts) Production expense $ 22,731 $ 1.50 $ 26,702 $ 1.39 General and administrative expense (excluding stock-based compensation and 5,448 0.36 7,981 0.42 employee-related asset disposition costs of $6,485 and $1,784, respectively) Interest expense 24,790 1.64 29,519 1.54 Current income tax (245 ) (0.02 ) (587 ) (0.03 ) benefit Total cash costs $ 52,724 $ 3.48 $ 63,615 $ 3.31 ________________________ Total cash costs is a non-GAAP measure that is used by management to assess the Company’s cash operating performance. Forest defines total cash costs as all cash operating costs, including production expense; general and administrative expense (excluding stock-based compensation and employee-related asset disposition costs); interest expense; and current income tax expense. Total Capital Expenditures Forest's exploration and development capital expenditures for the three months and the year-ended December 31, 2013, are set forth in the table below (in thousands): Three Months Ended Year Ended December 31, December 31, 2013 2013 Exploration and development $ 50,846 $ 324,822 Land and leasehold acquisitions 1,933 7,117 52,779 331,939 Add: ARO, capitalized interest, and 6,198 18,251 capitalized equity compensation Total capital expenditures $ 58,977 $ 350,190 ESTIMATED PROVED RESERVES Forest reported December 31, 2013 estimated proved reserves of 625 Bcfe, which were 66% proved developed, compared to 1,363 Bcfe at December 31, 2012, which were 69% proved developed. The decrease in estimated proved reserves was a result of 800 Bcfe of asset divestitures in 2013 partially offset by extensions and discoveries of 148 Bcfe. With continued focus on oil and liquids-rich drilling, extensions and discoveries were comprised of 66% oil and natural gas liquids and 34% natural gas. The pricing utilized for estimated proved reserves at December 31, 2013 was based on a 12-month average of the 2013 first-day-of-the-month Henry Hub price for natural gas and West Texas Intermediate price for oil of $3.67 per MMbtu and $97.33 per barrel, respectively. This compares to the pricing utilized for estimated proved reserves at December 31, 2012 for natural gas and oil of $2.76 per MMbtu and $94.79 per barrel, respectively. Forest's estimated proved reserves were audited by DeGolyer and MacNaughton (D&M), an independent third party engineering firm. D&M's audit covered properties representing over 87% of the value of Forest's total estimated proved reserves at year-end 2013. The following table reflects the 2013 activity related to the estimated proved reserves and includes calculations of reserve replacement ratio and finding and development costs utilizing net sales volumes and capital expenditures: Estimated Proved Reserves (Bcfe) December 31, 2012 1,363 Extensions and discoveries 148 Reserve additions 148 Net sales volumes (75 ) Sales of properties (800 ) Price-related revisions 40 Five year PUD limitation revision ^(1) (41 ) Other revisions (10 ) Reserve subtractions (886 ) December 31, 2013 625 Drill bit reserve replacement ratio excluding revisions 197 % ^(2) Drill bit finding and development costs excluding revisions $ 2.19 (per Mcfe) ^(3) Reserve : production ratio (years) ^ (4) 8.3 ^(1) The five year estimated proved undeveloped reserve limitation revision is related primarily to natural gas assets located in the Ark-La-Tex. The drill bit reserve replacement ratio excluding revisions of 197% was ^(2) calculated by dividing extensions and discoveries of 148 Bcfe by net sales volumes of 75 Bcfe. The drill bit finding and development costs, excluding revisions, of $2.19 per Mcfe was calculated by dividing the sum of exploration and ^(3) development capital expenditures (excluding land and leasehold acquisitions, asset retirement obligations, capitalized interest, and capitalized equity compensation) of $325 million by extensions and discoveries of 148 Bcfe. ^(4) The reserve to production ratio of 8.3 years was calculated by dividing proved reserves of 625 Bcfe by net sales volumes of 75 Bcfe. OPERATIONAL PROJECT UPDATE Eagle Ford Forest’s drilling and completion activity during 2013 was primarily focused on lease expirations in advance of transitioning to the development phase of the Eagle Ford program. The Company plans to hold through production a total of 49,000 gross (24,500 net) acres within Gonzales County, Texas. For 2013, Forest reported results on 44 gross (22 net) wells that had a 30-day average gross production rate of 408 Boe/d (95% oil). This includes 17 gross (8.5 net) wells that were completed since the Company’s last operational update that had a 30-day average gross production rate of 304 Boe/d (94% oil), including seven gross (3.5 net) wells that were drilled as part of two separate well spacing and artificial lift pilot projects and three gross (1.5 net) wells that were drilled in areas where the completions were adversely impacted by faulting. As is characteristic of field delineation efforts, initial production rates have varied as the Company focused on establishing and prioritizing its acreage position, gathering significant geologic and geophysical data, developing the optimal drilling, well completion, and fracture stimulation techniques, conducting well spacing tests, and identifying the most appropriate form of artificial lift. This data has provided a better understanding of the geologic and reservoir characteristics and attributes of the producing formation, which will be utilized during 2014 to determine well locations, assist in reducing costs, and enhance performance. Well spacing tests were conducted in two areas of the field in the fourth quarter to determine optimal spacing for the parts of the field that have distinct reservoir and production characteristics. Based on drilling and completion results and initial production data from these two projects, Forest believes that an average lateral spacing of 500-feet to 1,000-feet between wells will be the development configuration for the majority of the acreage position. Forest encountered greater-than-anticipated faulting in a portion of its southern acreage position that adversely impacted the flow rate of three wells. The fault complexes were located in an area where two of the Company’s seismic surveys overlap. Forest is in the process of merging and reprocessing its existing 3D seismic surveys so that it can more accurately identify and avoid fault complexes at the edge of the seismic surveys where the faulting was encountered. It is expected that the reprocessed data will be available and utilized to select drilling locations by the third quarter of 2014. Forest plans to focus its first half of 2014 drilling program in areas where it has a high degree of confidence in the geology, geophysical, and reservoir data and believes the fault patterns are accurately imaged. The southern area is considered to be the more productive part of the field and will be the primary focus of the 2014 drilling program. While the seismic is being reprocessed and optimal well design is being evaluated, Forest has elected to reduce the pace of drilling in the Eagle Ford. As such, the 2014 drilling plan will entail drilling 48 gross (24 net) wells. Forest expects that the net capital allocated to the Eagle Ford for drilling and completion activities in 2014 will total $95 million. Net sales volumes from the Eagle Ford averaged approximately 2,950 Boe/d in the fourth quarter of 2013. Drilling and completion costs averaged approximately $5.6 million per well in the fourth quarter and the average well cost in 2013 was 15% lower than 2012. Forest expects to see further improvement in well costs in 2014 through the continued optimization of drilling and completion techniques, the use of existing pad locations, and as the oil and gas gathering system and centralized production facility becomes operational during the second half of 2014. Ark-La-Tex Forest holds approximately 234,000 gross (162,000 net) acres in the greater Ark-La-Tex region, including East Texas, North Louisiana, and the Arkoma Basin. The Ark-La-Tex is largely held by production and provides repeatable and predictable drilling and recompletion opportunities in multiple natural gas, oil, and natural gas liquids horizons. During 2013, drilling activity focused on the liquids-rich Cotton Valley and other oil formations. During the fourth quarter of 2013, one Cotton Valley well was completed with a 30-day average gross production rate of 8.4 MMcfe/d (35% liquids or 490 Bbls/d). Forest drilled a total of six wells in 2013 that had a 30-day average gross production rate of 8.7 MMcfe/d (40% liquids). Net sales volumes for the Ark-La-Tex averaged approximately 93 MMcfe/d in the fourth quarter of 2013. A modified drilling and completion design was implemented in the latter part of 2013, which reduced the average well cost to approximately $7.5 million. This compares to an average well cost of $8.5 million for the other Cotton Valley wells drilled in 2013. Based on an improving price environment, lower drilling and completion costs, and excellent well results, Forest has elected to increase activity in East Texas and recently added a second operated rig to the program. A third operated rig is expected to begin drilling during the second quarter of 2014. Forest anticipates drilling 20-25 wells in East Texas in 2014. As part of an expanded Ark-La-Tex drilling program, Forest plans to continue development of a light sweet crude oil play in East Texas where it has successfully completed three horizontal producers since initiating this program in the second half of 2012. Forest currently holds approximately 19,000 gross (14,000 net) acres within this concentrated area. The Company is currently engaged in the integration of 3D seismic data with geological and well data and expects to commence additional drilling activity in this area during the second half of 2014. Management Comment Patrick R. McDonald, President and CEO, stated, “Our goals last year included accelerating development of our oil assets, improving our strategic direction by narrowing our operational focus, and reducing debt levels. In 2013, these objectives were achieved through the formation of a joint development partnership for our Eagle Ford asset and the execution of asset sales that generated proceeds of $1.3 billion. We were able to grow oil and liquids volumes by 55% and 41%, respectively, when compared to 2012 pro forma for divestitures. I am pleased that our team was able to accomplish these objectives. “Our drilling and completion activity in the Eagle Ford during 2013 was primarily focused on lease expirations and delineation drilling in advance of transitioning to the development phase of the program. Our Eagle Ford average well costs continued to improve during 2013 as we capitalized on operational synergies, technological advancements and more efficient well drilling and completion designs. Our average well costs for 2013 were 15% lower than 2012 and we see the potential for further and significant reductions in 2014. “As outlined in today’s update, we are electing to defer Eagle Ford drilling activity as we complete the reprocessing and interpretation of 3D seismic data and also evaluate the success of recent well completion designs. Importantly, we maintain a balanced portfolio of projects that provides attractive risk-adjusted rate-of-return opportunities. This will enable us to reallocate capital to our liquids-rich opportunities in the Ark-La-Tex to maintain a consistent level of drilling activity in 2014. This decision will result in lower oil growth for 2014; however, we believe this is a prudent capital allocation decision.” 2014 Guidance Forest is updating its 2014 guidance that was initially provided on December 2, 2013, as follows: *The drilling and completion capital budget will be allocated approximately 64% to the Ark-La-Tex and 36% to the Eagle Ford *Average net sales volumes are estimated to be comprised of approximately 35% oil and natural gas liquids and 65% natural gas *Production expense, which includes lease operating expense, ad valorem taxes, production taxes, and product processing, gathering and transportation is expected to average $1.55 to $1.65 per Mcfe *Depreciation, depletion and amortization expense is expected to be $2.45 to $2.65 per Mcfe A summary of 2014 guidance, including the changes outlined in today’s press release, is provided in the table below: Budget Low Budget High Drilling and Completion Capital Budget ($ $ 260 $ 270 million) Non-Drilling Capital Budget: Leasehold, Seismic, and Other ($ million) 10 15 Capitalized Overhead ($ million) 20 25 Total Capital Budget ($ million) $ 290 $ 310 Average Net Sales Volumes (MMcfe/d) 120 130 % Natural Gas 65.0 % 65.0 % % Oil 21.0 % 21.0 % % Natural Gas Liquids 14.0 % 14.0 % Production Expense ($ per Mcfe) $ 1.55 $ 1.65 Depreciation, Depletion and Amortization ($ per $ 2.45 $ 2.65 Mcfe) General and Administrative Expense ($ million) $ 28 $ 30 Stock-Based Compensation ($ million) $ 9 $ 11 Income Tax Rate 0 % 0 % Incorporating the impact of a slower pace of development in the Eagle Ford and lower-than-expected fourth quarter well results, first quarter of 2014 net sales volumes are expected to average 105 – 110 MMcfe/d (67% natural gas and 33% liquids). Based on current projections of planned 2014 activity, the Company expects fourth quarter of 2014 average net sales volumes to average 145 – 150 MMcfe/d (63% natural gas and 37% liquids). The following table provides a summary of 2013 average net sales volumes excluding asset sales and 2014 average net sales guidance by area: Average Net Sales Volumes (MMcfe/d) Region 1Q13A 2Q13A 3Q13A 4Q13A 1Q14E 4Q14E 2014 ^(1) ^(1) Guidance Ark-La-Tex 102 96 96 93 89 125 100 - 109 Eagle Ford 12 13 18 18 18 22 20 - 21 Total 114 109 114 111 108 148 120 - 130 ^(1) Assumes the mid-point of guidance range Forest’s guidance for 2014 remains subject to the cautionary statements and limitations contained in Forest’s December 2, 2013, press release under the caption “2014 Guidance” as well as those stated below under the caption “Forward-Looking Statements.” DERIVATIVE INSTRUMENTS As of February 25, 2014, Forest had natural gas and oil derivatives in place for 2014 and 2015 covering the aggregate average daily volumes and weighted average prices shown below: 2014 2015 Natural gas swaps: Contract volumes (Bbtu/d) 70.0 20.0 Weighted average price (per MMBtu) $ 4.38 $ 4.20 Natural gas collars: Contract volumes (Bbtu/d) - 4.9 Ceiling price (per MMBtu) $ - $ 5.31 Floor price (per MMBtu) $ - $ 4.50 Oil swaps: Contract volumes (MBbls/d) 3.5 - Weighted average price (per Bbl) $ 95.34 $ - In connection with entering into certain 2014 oil swaps with premium hedged prices, Forest sold oil puts that gave the counterparties the option to put 2,000 Bbls/d to Forest at a weighted average price of $70.00 per Bbl on a monthly basis during 2014. In connection with the execution of certain commodity swaps shown in the table above, Forest sold swaption instruments to counterparties in exchange for Forest receiving premium hedged prices on the swaps. The table below sets forth the outstanding swaptions as of February 25, 2014: 2015 2016 Natural gas swaptions: Contract volumes (Bbtu/d) - 10.0 Price (per MMBtu) $ - $ 4.18 Oil swaptions: Contract volumes (MBbls/d) 6.0 - Weighted average price (per Bbl) $ 100.79 $ - NON-GAAP FINANCIAL MEASURES Adjusted Net Earnings In addition to reporting net earnings (loss) as defined under generally accepted accounting principles (GAAP), Forest also presents adjusted net earnings, which is a non-GAAP performance measure. Adjusted net earnings consist of net earnings (loss) after adjustment for those items shown in the table below. Adjusted net earnings does not represent, and should not be considered an alternative to, GAAP measurements such as net earnings (loss) (its most comparable GAAP financial measure), and Forest's calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items shown below, Forest believes that the measure is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in the oil and gas industry. Forest's management does not view adjusted net earnings in isolation and also uses other measurements, such as net earnings (loss) and revenues, to measure operating performance. The following table provides a reconciliation of net earnings, the most directly comparable GAAP measure, to adjusted net earnings for the periods presented (in thousands): Three Months Ended Year Ended December 31, December 31, 2013 2012 2013 2012 Net earnings $ 106,219 $ (286,533 ) $ 73,924 $ (1,288,931 ) (loss) Net gain on asset (129,012 ) - (129,012 ) - dispositions, net of tax Ceiling test write-down of oil and natural 36,806 178,032 36,806 634,047 gas properties, net of tax Change in valuation allowance on deferred tax assets, net of non-deductible (38,151 ) 104,442 (26,799 ) 577,480 stock-based compensation costs, goodwill reduction, and other Impairment of properties, net - - - 50,811 of tax Employee-related asset disposition 3,893 - 8,156 3,835 costs, net of tax Rig stacking, 2,310 2,466 6,379 4,219 net of tax Net loss on debt extinguishment, 15,008 23,200 31,116 23,200 net of tax Unrealized losses (gains) on derivative 5,650 (4,615 ) 19,811 25,037 instruments, net of tax Legal proceeding costs, net of - - - 18,688 tax Adjusted net $ 2,723 $ 16,992 $ 20,381 $ 48,386 earnings Earnings attributable to (67 ) (406 ) (579 ) (1,138 ) participating securities Adjusted net earnings for $ 2,656 $ 16,586 $ 19,802 $ 47,248 diluted earnings per share Weighted average number of 116,559 115,477 116,125 114,960 diluted shares outstanding Adjusted diluted earnings per $ 0.02 $ 0.14 $ 0.17 $ 0.41 share Adjusted EBITDA In addition to reporting net earnings (loss) as defined under GAAP, Forest also presents adjusted net earnings before interest, income taxes, depreciation, depletion, amortization, and certain other items (adjusted EBITDA), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings (loss) after adjustment for those items shown in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to, GAAP measurements such as net earnings (loss) (its most comparable GAAP financial measure), and Forest's calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items shown below, Forest believes the measure is useful in evaluating its fundamental core operating performance. Forest also believes that adjusted EBITDA is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in the oil and gas industry. Forest's management uses adjusted EBITDA to manage its business, including in preparing its annual operating budget and financial projections. Forest's management does not view adjusted EBITDA in isolation and also uses other measurements, such as net earnings and revenues, to measure operating performance. The following table provides a reconciliation of net earnings, the most directly comparable GAAP measure, to adjusted EBITDA for the periods presented (in thousands): Three Months Ended Year Ended December 31, December 31, 2013 2012 2013 2012 Net earnings $ 106,219 $ (286,533 ) $ 73,924 $ (1,288,931 ) (loss) Income tax (benefit) (245 ) (1,832 ) (707 ) 173,437 expense Interest expense 24,790 37,899 119,829 141,831 Ceiling test write-down of 57,636 278,654 57,636 992,404 oil and natural gas properties Impairment of - - - 79,529 properties Depreciation, depletion, and 35,237 66,656 171,557 280,458 amortization Unrealized losses (gains) 8,847 (7,246 ) 30,923 39,126 on derivative instruments, net Gain on asset dispositions, (202,023 ) - (202,023 ) - net Stock-based 1,599 2,847 8,875 15,074 compensation Accretion of asset retirement 643 1,749 2,982 6,663 obligations Employee-related asset 5,357 - 11,178 1,851 disposition costs Legal proceeding - - - 29,251 costs Loss on debt 23,502 36,312 48,725 36,312 extinguishment Rig stacking 3,617 3,860 9,989 6,604 Adjusted EBITDA $ 65,179 $ 132,366 $ 332,888 $ 513,609 Adjusted Discretionary Cash Flow In addition to reporting net cash provided by operating activities as defined under GAAP, Forest also presents adjusted discretionary cash flow, which is a non-GAAP liquidity measure. Adjusted discretionary cash flow consists of net cash provided by operating activities after adjustment for those items shown in the table below. This measure does not represent, and should not be considered an alternative to, GAAP measurements such as net cash provided by operating activities (its most comparable GAAP financial measure), and Forest's calculations thereof may not be comparable to similarly titled measures reported by other companies. Forest's management uses adjusted discretionary cash flow as a measure of liquidity and believes it provides useful information to investors because it assesses cash flow from operations before changes in operating assets and liabilities, which fluctuate due to the timing of collections of receivables and the settlements of liabilities, and other items. Forest's management uses adjusted discretionary cash flow to manage its business, including in preparing its annual operating budget and financial projections. This measure does not represent the residual cash flow available for discretionary expenditures. Forest’s management does not view adjusted discretionary cash flow in isolation and also uses other measurements, such as net cash provided by operating activities, to measure operating performance. The following table provides a reconciliation of net cash provided by operating activities, the most directly comparable GAAP measure, to adjusted discretionary cash flow for the periods presented (in thousands): Three Months Ended Year Ended December 31, December 31, 2013 2012 2013 2012 Net cash provided by $ 17,774 $ 85,830 $ 201,759 $ 371,655 operating activities Changes in operating assets and liabilities: Accounts (29,614 ) (2,503 ) (31,816 ) (11,573 ) receivable Other current 2,392 1,796 (3,504 ) (2,630 ) assets Accounts payable and accrued 13,934 23,346 (1,560 ) 21,164 liabilities Accrued interest 27,079 (15,799 ) 28,996 (2,322 ) and other Current income tax credit/income - - - (33,327 ) tax-carryback ^(1) Employee-related asset 5,357 - 11,178 1,851 disposition costs ^(1) Legal proceeding - - - 29,251 costs^(1) Adjusted discretionary $ 36,922 $ 92,670 $ 205,053 $ 374,069 cash flow The current income tax credit/income tax carryback, employee-related asset disposition costs, and legal proceeding costs are non-recurring cash-settled items. Including the effect of these items, adjusted (1) discretionary cash flow would have been $32 million and $93 million for the three months ended December 31, 2013 and 2012, respectively, and $194 million and $376 million for the years ended December 31, 2013 and 2012, respectively. Net Debt In addition to reporting total debt as defined under GAAP, Forest also presents net debt, which is a non-GAAP debt measure. Net debt consists of the principal amount of debt adjusted for cash and cash equivalents at the end of the period. Forest's management uses net debt to assess Forest's indebtedness. The following table sets forth the components of net debt (in thousands): December 31, 2013 December 31, 2012 Principal Book^(1) Principal Book^(1) Credit facility $ - $ - $ 65,000 $ 65,000 7% Senior subordinated notes - - 12 12 due 2013 8 1/2% Senior notes due 2014 - - 300,000 296,723 ^(2) 7 1/4% Senior notes due 2019 577,914 578,092 1,000,000 1,000,365 ^(3) 7 1/2% Senior notes due 2020 222,087 222,087 500,000 500,000 ^(3) Total debt 800,001 800,179 1,865,012 1,862,100 Less: cash and 66,192 66,192 1,056 1,056 cash equivalents Net debt $ 733,809 $ 733,987 $ 1,863,956 $ 1,861,044 Book amounts include the principal amount of debt adjusted for ^(1) unamortized premiums (discounts) on the issuance of certain senior notes of $0.2 million and $(2.9) million at December 31, 2013 and 2012, respectively. In March 2013, Forest redeemed the $300 million 8 1/2% Senior notes due ^(2) February 15, 2014 using the South Texas divestiture proceeds and borrowings on the credit facility. In November 2013, Forest redeemed $700 million in aggregate principal ^(3) amount of the 7 1/4% Senior notes due June 15, 2019 and 7 1/2% Senior notes due September 15, 2020 using a portion of the Texas Panhandle divestiture proceeds. TELECONFERENCE CALL A conference call is scheduled for Wednesday, February 26, 2014, at 7:00 AM MT to discuss the release. You may access the call by dialing toll free 800.295.4740 (for U.S./Canada) and 617.614.3925 (for International) and request the Forest Oil teleconference (ID # 57263063). The conference call will also be webcast live on the Internet and can be accessed by going to the Forest Oil website at www.forestoil.com in the “Investor Relations” section of the website. A Q&A period will follow. A replay of the conference call will be available through March 5, 2014. You may access the replay by dialing toll free 888.286.8010 (for U.S./Canada) and 617.801.6888 (for International), conference ID # 59682985. An archive of the conference call webcast will also be available at www.forestoil.com in the “Investor Relations” section of the website. FORWARD-LOOKING STATEMENTS This news release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, that address activities that Forest assumes, plans, intends, expects, believes, projects, estimates or anticipates (and other similar expressions) will, should, or may occur in the future are forward-looking statements. The forward-looking statements provided in this press release are based on management's current belief, based on currently available information, as to the outcome and timing of future events. Forest cautions that future natural gas and liquids production, revenues, cash flows, liquidity, plans for future operations, expenses, outlook for oil and natural gas prices, timing of capital expenditures, timing and terms of any divestitures, and other forward-looking statements relating to Forest are subject to all of the risks and uncertainties normally incident to the exploration for and development and production and sale of liquids and natural gas. These risks relating to Forest include, but are not limited to, oil and natural gas price volatility, its level of indebtedness, its ability to replace production, its ability to compete with larger producers, environmental risks, drilling and other operating risks, regulatory changes, credit risk of financial counterparties, risks of using third-party transportation and processing facilities, the decision to sell or offer for sale, or to determine not to sell any portion of its assets, the ability to enter into agreements relating to such sales on desirable terms or at all, the timing of any such agreements, the ability to consummate any such sales, the ability to realize the anticipated benefits of any such sales, the ability to determine the use of proceeds from any such sales, the ability to determine whether to reduce outstanding indebtedness and the amount and timing of any such reductions, and other risks as described in reports that Forest files with the SEC, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K. Any of these factors could cause Forest's actual results and plans to differ materially from those in the forward-looking statements. Forest Oil Corporation is engaged in the acquisition, exploration, development, and production of natural gas and liquids in the United States. Forest's principal reserves and producing properties are located in the United States in Arkansas, Louisiana, Oklahoma, and Texas. Forest's common stock trades on the New York Stock Exchange under the symbol FST. For more information about Forest, please visit its website at www.forestoil.com. February 25, 2014 FOREST OIL CORPORATION Condensed Consolidated Balance Sheets (Unaudited) December 31, December 31, 2013 2012 ASSETS (In thousands) Current assets: Cash and cash equivalents $ 66,192 $ 1,056 Accounts receivable 35,654 67,516 Derivative instruments 5,192 40,190 Other current assets 6,756 16,318 Total current assets 113,794 125,080 Net property and equipment 818,569 1,754,238 Deferred income taxes 2,230 14,681 Goodwill 134,434 239,420 Derivative instruments 400 8,335 Other assets 48,525 60,108 $ 1,117,952 $ 2,201,862 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable and accrued $ 141,107 $ 164,786 liabilities Accrued interest 6,654 23,407 Derivative instruments 4,542 9,347 Deferred income taxes 2,230 14,681 Other current liabilities 12,201 14,104 Total current liabilities 166,734 226,325 Long-term debt 800,179 1,862,088 Asset retirement obligations 22,629 56,155 Derivative instruments - 7,204 Other liabilities 73,941 92,914 Total liabilities 1,063,483 2,244,686 Shareholders' equity: Common stock 11,940 11,825 Capital surplus 2,554,997 2,541,859 Accumulated deficit (2,502,070 ) (2,575,994 ) Accumulated other comprehensive loss (10,398 ) (20,514 ) Total shareholders' equity 54,469 (42,824 ) (deficit) $ 1,117,952 $ 2,201,862 FOREST OIL CORPORATION Condensed Consolidated Statements of Operations (Unaudited) Three Months Ended Year Ended December 31, December 31, 2013 2012 2013 2012 (In thousands, except per share amounts) Revenues: Oil, gas, and $ 88,485 $ 154,914 $ 441,341 $ 605,523 NGL sales Interest and 5 13 331 136 other Total 88,490 154,927 441,672 605,659 revenues Costs, expenses, and other: Lease operating 17,059 25,860 76,675 108,027 expenses Production and 2,945 7,314 14,857 34,249 property taxes Transportation and processing 2,727 3,466 11,895 14,633 costs General and administrative 11,933 14,041 54,826 59,262 expense Depreciation, depletion, and 35,237 66,656 171,557 280,458 amortization Ceiling test write-down of oil and 57,636 278,654 57,636 992,404 natural gas properties Impairment of - - - 79,529 properties Interest 24,790 37,899 119,829 141,831 expense Realized and unrealized losses (gains) 4,283 (31,902 ) 3,786 (72,646 ) on derivative instruments, net Other, net (174,094 ) 41,304 (142,606 ) 83,406 Total costs, (17,484 ) 443,292 368,455 1,721,153 expenses, and other Earnings (loss) before 105,974 (288,365 ) 73,217 (1,115,494 ) income taxes Income tax (benefit) (245 ) (1,832 ) (707 ) 173,437 expense Net earnings $ 106,219 $ (286,533 ) $ 73,924 $ (1,288,931 ) (loss) Basic and diluted weighted 116,559 115,477 116,125 114,958 average shares outstanding Basic and diluted earnings $ 0.89 $ (2.48 ) $ 0.62 $ (11.21 ) (loss) per common share FOREST OIL CORPORATION Condensed Consolidated Statements of Cash Flows (Unaudited) Three Months Ended Year Ended December 31, December 31, 2013 2012 2013 2012 (In thousands) Operating activities: Net earnings $ 106,219 $ (286,533 ) $ 73,924 $ (1,288,931 ) (loss) Adjustments to reconcile net earnings (loss) to net cash provided by operating activities: Depreciation, depletion, and 35,237 66,656 171,557 280,458 amortization Deferred income tax - (15 ) - 208,975 expense (benefit) Unrealized losses (gains) on derivative 8,847 (7,246 ) 30,923 39,126 instruments, net Ceiling test write-down of oil and 57,636 278,654 57,636 992,404 natural gas properties Impairment of - - - 79,529 properties Stock-based 1,599 2,847 8,875 15,074 compensation Gain on asset dispositions, (202,023 ) - (202,023 ) - net Loss on debt 23,502 36,312 48,725 36,312 extinguishment Other, net 548 1,995 4,258 13,347 Changes in operating assets and liabilities: Accounts 29,614 2,503 31,816 11,573 receivable Other current (2,392 ) (1,796 ) 3,504 2,630 assets Accounts payable and (13,934 ) (23,346 ) 1,560 (21,164 ) accrued liabilities Accrued interest and other (27,079 ) 15,799 (28,996 ) 2,322 current liabilities Net cash provided by 17,774 85,830 201,759 371,655 operating activities Investing activities: Capital expenditures for property and equipment: Exploration, development, acquisition, (73,048 ) (122,654 ) (363,971 ) (721,536 ) and leasehold costs Other fixed (251 ) (3,117 ) (1,517 ) (9,128 ) assets Proceeds from 976,679 253,980 1,347,116 262,882 sales of assets Net cash provided (used) by 903,380 128,209 981,628 (467,782 ) investing activities Financing activities: Proceeds from 72,000 593,000 529,000 1,244,000 bank borrowings Repayments of (187,000 ) (528,000 ) (594,000 ) (1,284,000 ) bank borrowings Issuance of senior notes, - - - 491,250 net of issuance costs Redemption of (715,847 ) (330,709 ) (1,037,174 ) (330,709 ) senior notes Change in bank (25,541 ) 13,499 (14,424 ) (24,217 ) overdrafts Other, net (695 ) 58 (1,653 ) (2,153 ) Net cash (used) provided (857,083 ) (252,152 ) (1,118,251 ) 94,171 by financing activities Net increase (decrease) in 64,071 (38,113 ) 65,136 (1,956 ) cash and cash equivalents Cash and cash equivalents at 2,121 39,169 1,056 3,012 beginning of period Cash and cash equivalents at $ 66,192 $ 1,056 $ 66,192 $ 1,056 end of period Contact: Forest Oil Corporation Larry C. Busnardo, 303-812-1441 VP – Investor Relations
Forest Oil Announces Fourth Quarter and Year-End 2013 Results
Press spacebar to pause and continue. Press esc to stop.