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Supplementary Information For Oil And Gas Producing Activities
12 Months Ended
Sep. 30, 2014
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]  
Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)
Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)
The Company follows authoritative guidance related to oil and gas exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows. The SEC rules require companies to value their year-end reserves using an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve month period prior to the end of the reporting period.
The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about oil and gas producing activities and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.
 
Capitalized Costs Relating to Oil and Gas Producing Activities
 
 
At September 30
 
2014
 
2013
 
(Thousands)
Proved Properties(1)
$
3,941,143

 
$
3,393,612

Unproved Properties
141,719

 
106,085

 
4,082,862

 
3,499,697

Less — Accumulated Depreciation, Depletion and Amortization
1,211,610

 
919,989

 
$
2,871,252

 
$
2,579,708

 
(1)
Includes asset retirement costs of $75.7 million and $80.6 million at September 30, 2014 and 2013, respectively.
Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Although the timing of the ultimate evaluation or disposition of the unproved properties cannot be determined, the Company expects the majority of its acquisition costs associated with unproved properties to be transferred into the amortization base by 2020. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2015. Following is a summary of costs excluded from amortization at September 30, 2014:
 
 
Total
as of
September 30,
2014
 
Year Costs Incurred
 
 
2014
 
2013
 
2012
 
Prior
 
(Thousands)
Acquisition Costs
$
61,712

 
$
7,057

 
$
905

 
$
5,585

 
$
48,165

Development Costs
42,362

 
39,339

 
677

 
1,405

 
941

Exploration Costs
36,882

 
36,882

 

 

 

Capitalized Interest
763

 
763

 

 

 

 
$
141,719

 
$
84,041

 
$
1,582

 
$
6,990

 
$
49,106


Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands)
United States
 
Property Acquisition Costs:
 
 
 
 
 
Proved
$
18,213

 
$
7,575

 
$
13,095

Unproved
7,884

 
9,274

 
13,867

Exploration Costs(1)
71,850

 
49,483

 
84,624

Development Costs(2)
490,164

 
460,554

 
576,397

Asset Retirement Costs
(4,946
)
 
37,546

 
10,344

 
$
583,165

 
$
564,432

 
$
698,327

 
(1)
Amounts for 2014, 2013 and 2012 include capitalized interest of $0.7 million, $0.4 million and $1.0 million, respectively.
(2)
Amounts for 2014, 2013 and 2012 include capitalized interest of $0.7 million, $0.7 million and $2.0 million, respectively.
For the years ended September 30, 2014, 2013 and 2012, the Company spent $179.9 million, $148.5 million and $216.6 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands, except per Mcfe amounts)
United States
 
 
 
 
 
Operating Revenues:
 
 
 
 
 
Natural Gas (includes revenues from sales to affiliates of $1 for all years presented and transfers to operations of $2,145, $612 and $0, respectively)
$
515,080

 
$
371,311

 
$
181,544

Oil, Condensate and Other Liquids
298,179

 
291,762

 
307,018

Total Operating Revenues(1)
813,259

 
663,073

 
488,562

Production/Lifting Costs
165,534

 
119,243

 
83,361

Franchise/Ad Valorem Taxes
20,765

 
17,200

 
23,620

Accretion Expense
6,192

 
3,929

 
3,084

Depreciation, Depletion and Amortization ($1.82, $1.98 and $2.19 per Mcfe of production)
291,651

 
238,467

 
182,759

Income Tax Expense
140,484

 
120,431

 
81,904

Results of Operations for Producing Activities (excluding corporate overheads and interest charges)
$
188,633

 
$
163,803

 
$
113,834

 
(1)
Exclusive of hedging gains and losses. See further discussion in Note G — Financial Instruments.
Reserve Quantity Information
The Company’s proved oil and gas reserve estimates are prepared by the Company’s reservoir engineers who meet the qualifications of Reserve Estimator per the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.
The Company’s Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company’s reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 25 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company’s reserve estimation process for the past eleven years. He is a member of the Society of Petroleum Engineers and a Registered Professional Engineer in the State of Texas.
The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model that determines the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company’s internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.
All of the Company’s reserve estimates are audited annually by Netherland, Sewell and Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include a professional engineer registered with the State of Texas (consulting at NSAI since 2004 and with over 5 years of prior industry experience in petroleum engineering) and a professional geoscientist registered in the State of Texas (consulting at NSAI since 2008 with over 11 years of prior industry experience in petroleum geosciences). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2014 and did not identify any problems which would cause it to take exception to those estimates.
 
The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, 2D and 3D seismic data and statistical analysis. The statistical method utilized production performance from both the Company’s and competitors’ wells. Geophysical data includes data from the Company’s wells, published documents, state data-sites and 2D and 3D seismic data. This data was used to confirm continuity of the formation.

 
 
Gas MMcf
 
U. S.
 
 
 
Appalachian
Region
 
West
Coast
Region
 
Total
Company
Proved Developed and Undeveloped Reserves:
 
 
 
 
 
September 30, 2011
606,606

  
68,316

 
674,922

Extensions and Discoveries
435,460

(1)
638

 
436,098

Revisions of Previous Estimates
(53,992
)
 
(2,463
)
 
(56,455
)
Production
(62,663
)
(2)
(3,468
)
 
(66,131
)
September 30, 2012
925,411

  
63,023

 
988,434

Extensions and Discoveries
360,922

(1)
702

 
361,624

Revisions of Previous Estimates
53,038

  
112

 
53,150

Production
(100,633
)
(2)
(3,060
)
 
(103,693
)
September 30, 2013
1,238,738

  
60,777

 
1,299,515

Extensions and Discoveries
446,821

(1)

 
446,821

Revisions of Previous Estimates
43,690

  
1,358

 
45,048

Production
(139,097
)
(2)
(3,210
)
 
(142,307
)
Purchases of Minerals in Place
33,986

 

 
33,986

Sale of Minerals in Place
(76
)
 
(103
)
 
(179
)
September 30, 2014
1,624,062

  
58,822

 
1,682,884

Proved Developed Reserves:
 
 
 
 


September 30, 2011
350,458

  
63,965

 
414,423

September 30, 2012
544,560

  
59,923

 
604,483

September 30, 2013
807,055

  
59,862

 
866,917

September 30, 2014
1,119,901

  
57,907

 
1,177,808

Proved Undeveloped Reserves:
 
 
 
 


September 30, 2011
256,148

  
4,351

 
260,499

September 30, 2012
380,851

  
3,100

 
383,951

September 30, 2013
431,683

  
915

 
432,598

September 30, 2014
504,161

  
915

 
505,076

 
(1)
Extensions and discoveries include 435 Bcf (during 2012), 355 Bcf (during 2013) and 442 Bcf (during 2014), of Marcellus Shale gas in the Appalachian Region.
(2)
Production includes 55,812 MMcf (during 2012), 93,999 MMcf (during 2013) and 131,590 MMcf (during 2014), from Marcellus Shale fields (which exceed 15% of total reserves).

 
Oil Mbbl
 
U. S.
 
 
 
Appalachian
Region
 
West
Coast
Region
 
Total
Company
Proved Developed and Undeveloped Reserves:
 
 
 
 
 
September 30, 2011
279

 
43,066

 
43,345

Extensions and Discoveries
28

 
1,229

 
1,257

Revisions of Previous Estimates
35

 
1,095

 
1,130

Production
(36
)
 
(2,834
)
 
(2,870
)
September 30, 2012
306

 
42,556

 
42,862

Extensions and Discoveries

 
2,443

 
2,443

Revisions of Previous Estimates
5

 
(881
)
 
(876
)
Production
(28
)
 
(2,803
)
 
(2,831
)
September 30, 2013
283

 
41,315

 
41,598

Extensions and Discoveries
18

 
1,521

 
1,539

Revisions of Previous Estimates
(17
)
 
(1,677
)
 
(1,694
)
Production
(31
)
 
(3,005
)
 
(3,036
)
Purchases of Minerals in Place

 
83

 
83

Sales of Minerals in Place

 
(13
)
 
(13
)
September 30, 2014
253

 
38,224

 
38,477

Proved Developed Reserves:
 
 
 
 

September 30, 2011
274

 
37,306

 
37,580

September 30, 2012
306

 
38,138

 
38,444

September 30, 2013
283

 
38,082

 
38,365

September 30, 2014
253

 
37,002

 
37,255

Proved Undeveloped Reserves:
 
 
 
 


September 30, 2011
5

 
5,760

 
5,765

September 30, 2012

 
4,418

 
4,418

September 30, 2013

 
3,233

 
3,233

September 30, 2014

 
1,222

 
1,222


The Company’s proved undeveloped (PUD) reserves increased from 452 Bcfe at September 30, 2013 to 512 Bcfe at September 30, 2014. PUD reserves in the Marcellus Shale increased from 432 Bcf at September 30, 2013 to 504 Bcf at September 30, 2014. The Company’s total PUD reserves were 27% of total proved reserves at September 30, 2014, down from 29% of total proved reserves at September 30, 2013.
The Company’s PUD reserves increased from 410 Bcfe at September 30, 2012 to 452 Bcfe at September 30, 2013. PUD reserves in the Marcellus Shale increased from 381 Bcf at September 30, 2012 to 432 Bcf at September 30, 2013. The Company’s total PUD reserves were 29% of total proved reserves at September 30, 2013, down from 33% of total proved reserves at September 30, 2012.
The increase in PUD reserves in 2014 of 60 Bcfe is a result of 290 Bcfe in new PUD reserve additions (288 Bcfe from the Marcellus Shale), 20 Bcfe in PUD reserves acquired, 12 Bcfe in upward revisions to remaining PUD reserves, offset by 229 Bcfe in PUD conversions to developed reserves and 33 Bcfe in PUD reserves removed. The PUD reserves removed were primarily in the Marcellus Shale (24 Bcfe) in Seneca’s non-operated joint venture in Clearfield County where the operator had previously drilled and cased the horizontal wells to total depth and does not appear now to have firm plans for their completion. An additional 9 Bcfe (1,501 Mbbl) of PUD reserves were removed at the Midway Sunset field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing capital elsewhere.
The increase in PUD reserves in 2013 of 42 Bcfe is a result of 221 Bcfe in new PUD reserve additions (219 Bcfe from the Marcellus Shale), offset by 160 Bcfe in PUD conversions to developed reserves and 19 Bcfe in downward PUD revisions. The downward revisions were primarily due to reductions to planned lateral lengths for several horizontal wells in the Marcellus Shale.
The Company invested $180 million during the year ended September 30, 2014 to convert 229 Bcfe (248 Bcfe including revisions) of PUD reserves to developed reserves. This represents 51% of the PUD reserves booked at September 30, 2013. The Company invested $149 million during the year ended September 30, 2013 to convert 160 Bcfe (171 Bcfe including revisions) of September 30, 2012 PUD reserves to proved developed reserves. This represented 39% of the PUD reserves booked at September 30, 2012. In 2015, the Company estimates that it will invest approximately $239 million to develop its PUD reserves. The Company is committed to developing its PUD reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. Since that rule, and over the last five years, the Company developed 19% of its beginning year PUD reserves in fiscal 2010, 47% of its beginning year PUD reserves in fiscal 2011, 33% of its beginning year PUD reserves in fiscal 2012, 39% of its beginning year PUD reserves in fiscal 2013 and 51% of its beginning year PUD reserves in fiscal 2014.
At September 30, 2014, the Company does not have a material concentration of proved undeveloped reserves that have been on the books for more than five years at the corporate level, country level or field level. All of the Company’s proved reserves are in the United States.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands)
United States
 
 
 
 
 
Future Cash Inflows
$
10,001,545

 
$
8,943,942

 
$
7,373,129

Less:
 
 
 
 
 
Future Production Costs
2,795,657

 
2,334,393

 
1,919,530

Future Development Costs
790,033

 
749,876

 
619,573

Future Income Tax Expense at Applicable Statutory Rate
2,434,370

 
2,113,101

 
1,812,055

Future Net Cash Flows
3,981,485

 
3,746,572

 
3,021,971

Less:
 
 
 
 
 
10% Annual Discount for Estimated Timing of Cash Flows
1,914,607

 
1,780,206

 
1,552,180

Standardized Measure of Discounted Future Net Cash Flows
$
2,066,878

 
$
1,966,366

 
$
1,469,791


The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
 
 
Year Ended September 30
 
2014
 
2013
 
2012
 
(Thousands)
United States
 
 
 
 
 
Standardized Measure of Discounted Future
 
 
 
 
 
Net Cash Flows at Beginning of Year
$
1,966,366

 
$
1,469,791

 
$
1,524,157

Sales, Net of Production Costs
(626,960
)
 
(526,630
)
 
(381,581
)
Net Changes in Prices, Net of Production Costs
(38,723
)
 
339,655

 
(385,019
)
Extensions and Discoveries
381,008

 
390,255

 
224,474

Changes in Estimated Future Development Costs
68,731

 
6,117

 
29,627

Purchases of Minerals in Place
34,705

 

 

Sales of Minerals in Place
(691
)
 

 

Previously Estimated Development Costs Incurred
179,502

 
148,535

 
252,967

Net Change in Income Taxes at Applicable Statutory Rate
(231,807
)
 
(130,574
)
 
(19,280
)
Revisions of Previous Quantity Estimates
55,184

 
34,864

 
103,472

Accretion of Discount and Other
279,563

 
234,353

 
120,974

Standardized Measure of Discounted Future Net Cash Flows at End of Year
$
2,066,878

 
$
1,966,366

 
$
1,469,791